EXHIBIT 99.3
                                                                   ------------


M A N A G E M E N T ' S   D I S C U S S I O N   A N D   A N A L Y S I S


This  management's  discussion and analysis ("MD&A") is dated February 20, 2007
and  should be read in  conjunction  with the  audited  consolidated  financial
statements  for the year ended  December 31, 2006 and the audited  consolidated
financial statements and MD&A for the year ended December 31, 2005 and MD&A for
the quarters ended March 31, 2006, June 30, 2006 and September 30, 2006.

NON-GAAP MEASURES

Management  uses  cash  flow,  cash  flow  from  operations  and cash flow from
operations  per unit derived from cash flow from operating  activities  (before
changes in non-cash  working capital and  expenditures on site  reclamation and
restoration)  to  analyze  operating  performance  and  leverage.  Cash flow as
presented  does  not have  any  standardized  meaning  prescribed  by  Canadian
generally accepted accounting principles,  ("GAAP") and therefore it may not be
comparable  with the calculation of similar  measures for other entities.  Cash
flow as presented is not intended to represent operating cash flow or operating
profits for the period nor should it be viewed as an  alternative  to cash flow
from  operating  activities,  net  earnings  or  other  measures  of  financial
performance calculated in accordance with Canadian GAAP.

The following table reconciles the cash flow from operating  activities to cash
flow from operations which is used frequently in this MD&A:

===============================================================================
($ millions)                                                2006        2005
===============================================================================
Cash flow from operating activities                         734.0      616.7
Changes in non-cash working capital                          16.0       17.9
Expenditures on site reclamation and restoration             10.6        4.9
-------------------------------------------------------------------------------
Cash flow from operations                                   760.6      639.5
===============================================================================

Management  uses  certain key  performance  indicators  ("KPI's")  and industry
benchmarks  such  as  payout  ratio,  operating  netbacks  ("netbacks"),  total
capitalization,  finding,  development  and acquisition  costs,  recycle ratio,
reserve  life  index,  reserves  per unit and  production  per unit to  analyze
financial  and  operating  performance.  Management  feels that these KPI's and
benchmarks are a key measure of profitability  and overall  sustainability  for
the Trust. These KPI's and benchmarks as presented do not have any standardized
meaning  prescribed by Canadian  GAAP and therefore may not be comparable  with
the calculation of similar measures for other entities.


FOURTH QUARTER FINANCIAL AND OPERATIONAL RESULTS

The Trust had an active  fourth  quarter  with the  closing  of $93  million of
acquisitions and $121.9 million spent on capital  development  activities which
contributed  to quarterly  average  production of 63,663 boe per day. The Trust
had a payout  ratio  of 70 per cent and  funded  $48.8  million  of its  fourth
quarter capital  development  program with cash flow. The fourth quarter was an
active  one for the  Trust  with the  drilling  of 59 gross  wells on  operated
properties and new production coming on-stream.

Late in the fourth quarter, natural gas prices started to recover to levels not
seen since the first  quarter of 2006,  however,  oil prices  declined.  Due to
increasing  electricity prices, the Trust's fourth quarter operating costs were
higher than previous quarters of 2006. Late in the quarter,  electricity prices
declined so as to be more in line with historical levels.

The Government's  proposed Trust taxation  announcement on October 31, 2006 was
an  unforeseen  event in the fourth  quarter  of 2006 and it had a  significant
impact throughout the trust sector. With the government announcement, there was
a significant  devaluation  in trust unit prices and a mass "sell off" of trust
units  whereby the Trust  incurred an  approximate  20 per cent decrease in the
trust unit price and a resulting  negative  total return to  unitholders in the
fourth quarter and 2006 as a whole.  Despite this event, ARC's core business is
unchanged and the Trust's  financial  results are strong as indicated by record
levels of production,  revenue,  capital spending,  net income,  cash flow, and
distributions to unitholders in 2006.

Refer to "Quarterly Historical Review" in this MD&A for key quarterly financial
and operational results.

o    The Trust's fourth quarter  production was 63,663 boe per day, an increase
     of eight per cent from the fourth quarter of 2005 due to  acquisitions  in
     late 2005 and during 2006.

o    Cash flow decreased to $174.4 million ($0.85 per unit) from $207.6 million
     ($1.07 per unit) in the fourth  quarter  of 2005.  Despite  eight per cent
     higher  volumes  in  the  fourth  quarter  of  2006,  significantly  lower
     commodity  prices and higher  operating costs were the key contributors to
     the lower cash flow.  Fourth  quarter cash  hedging  gains of $9.8 million
     partially  offset the lower  commodity  prices (cash  hedging  losses were
     $26.4 million in the fourth quarter of 2005).

o    Net income decreased to $56.6 million ($0.28 per unit) from $130.5 million
     ($0.68 per unit) in the fourth  quarter of 2005.  In  addition to the cash
     flow items listed above,  2006 net income decreased due to a $19.8 million
     increase  in  foreign   exchange  losses,  a  $22.5  million  increase  in
     depletion,  a $24.2  million  decrease in non-cash  gains on commodity and
     foreign  currency  contracts  offset by a $16.1 million decrease in future
     income tax expense and an $7.9 million decrease in the non-cash portion of
     general and administrative ("G&A") expenses as compared to 2005.

o    The Trust  maintained  fourth quarter  distributions at $0.20 per unit per
     month and paid out $122.3  million  for a payout  ratio of 70 per cent (56
     per cent in the fourth  quarter of 2005).  The remaining  $52.1 million of
     fourth  quarter cash flow was used to fund $48.8  million (40 per cent) of
     the capital expenditure program and contribute $3.4 million to the Trust's
     reclamation funds, including interest.

<PAGE>

o    Both oil and  natural  gas prices  recovered  slightly  late in the fourth
     quarter,  however the total realized price for the quarter was 26 per cent
     lower than in 2005 due primarily to significantly lower natural gas prices
     and  a  stronger   Canadian   dollar  which  resulted  in  lower  Canadian
     denominated  commodity  prices.  The WTI oil price  averaged  US$60.22 per
     barrel in the fourth quarter,  effectively  unchanged from US$60.05 barrel
     in  2005.  The  stronger  Canadian  dollar  resulted  in a lower  Canadian
     denominated  oil price of $68.60 per barrel  relative to $70.45 per barrel
     in 2005.  The AECO  monthly  natural gas price was $6.36 per mcf, a 46 per
     cent decrease  compared to the fourth  quarter of 2005. The total realized
     price was $49.94 per boe, a 26 per cent  decrease  compared  to $67.16 per
     boe in the fourth quarter of 2005.

o    The fourth  quarter  netback  before  hedging  decreased to $31.37 per boe
     compared  to $45.84 per boe in 2005 due to a 26 per cent  decrease  in the
     realized price per boe. In addition,  operating  costs  increased to $9.13
     per boe in 2006  due to the  higher  cost  Redwater  and  NPCU  properties
     acquired  in late 2005.  Alberta  electricity  prices  were  significantly
     higher in the fourth  quarter of 2006  relative  to 2005 and  service  and
     labour costs  increased  throughout  the industry in 2006 relative to 2005
     levels.

o    The Trust  spent  $121.9  million on capital  development  activities  and
     undeveloped  land in the fourth quarter compared to $87.8 million in 2005.
     The Trust had a very active  fourth  quarter with the drilling of 59 gross
     wells (45 net wells) on operated  properties  with a 100 per cent  success
     rate. The Trust  expanded its inventory of  undeveloped  land acreage with
     the  purchase  of $11.9  million of land in the fourth  quarter.  The land
     acquired  was in core  areas  where  the Trust  has  identified  strategic
     development opportunities.

o    Net debt levels  increased  to $739.1  million in the fourth  quarter as a
     result of $93 million of acquisitions and debt funded capital expenditures
     of $44.4  million.  A devaluation of the Canadian  dollar  relative to the
     U.S.  dollar also  impacted  the Trust's net debt levels as 71 per cent of
     the Trust's  debt is  denominated  in U.S.  dollars.  With the higher debt
     levels,  interest expense increased to $8.7 million ($1.48 per boe) in the
     fourth quarter compared to $6 million ($1.11 per boe) in 2005.

o    Cash G&A  expenses  increased  to $1.74 per boe from  $1.39 per boe in the
     fourth  quarter of 2005.  The  increased  G&A expenses  were due to higher
     compensation  costs in 2006.  In  addition,  the Trust made a $0.7 million
     cash  payout  under the Whole  Unit Plan for units  vesting  in the fourth
     quarter while no units vested in the fourth quarter of 2005.  Non-cash G&A
     per boe  decreased  significantly  in the fourth  quarter of 2006,  with a
     recovery of $0.02 per boe  compared to an expense of $1.43 per boe in 2005
     due to the  devaluation  of the trust unit price  following  the  proposed
     Trust taxation announcement on October 31, 2006, which resulted in a lower
     value of the Whole Unit Plan and resultant non-cash expense.  In addition,
     the Trust recorded lower non-cash  rights expense in the fourth quarter of
     2006 due to  majority  of the  rights  having  vested  and thus been fully
     expensed early in 2006.

<TABLE>
<CAPTION>
FOURTH QUARTER FINANCIAL AND OPERATIONAL HIGHLIGHTS

=================================================================================================
(CDN$ millions except per unit and per cent)           Q4 2006           Q4 2005       % Change
=================================================================================================
<S>                                                 <C>               <C>              <C>
Production (boe/d)                                      63,663            59,120              8
Cash flow from operations                                174.4             207.6            (16)
   Per unit                                         $     0.85        $     1.07            (21)
Cash distributions                                       122.3             115.7              6
   Per unit                                         $     0.60        $     0.60              -
Payout ratio (per cent)                                     70                56             26
Net income                                                56.6             130.5            (57)
   Per unit                                         $     0.28        $     0.68            (59)
-------------------------------------------------------------------------------------------------
Prices
   WTI (US$/bbl)                                         60.22             60.05              -
   USD/CAD exchange rate                                  0.87              0.85              3
   Realized oil price (CDN $/bbl)                        58.26             62.12             (6)
   AECO gas monthly index (CDN $/mcf)                     6.36             11.68            (46)
   Realized gas price (CDN $/mcf)                         6.99             12.05            (42)
-------------------------------------------------------------------------------------------------
Operating netback ($/boe)
   Revenue, before hedging                               49.94             67.16            (26)
   Royalties                                             (8.80)           (13.51)           (35)
   Transportation                                        (0.64)            (0.65)            (1)
   Operating costs                                       (9.13)            (7.16)            28
   Netback (before hedging)                              31.37             45.84            (32)
   Cash hedging gain (loss)                               1.68             (4.86)          (135)
   Netback (after hedging)                          $    33.05        $    40.98            (20)
-------------------------------------------------------------------------------------------------
Capital expenditures                                     121.9              87.8             39
-------------------------------------------------------------------------------------------------
Capital funded with cash flow (per cent)                    40               106              -
=================================================================================================
</TABLE>

<PAGE>

2006 ANNUAL FINANCIAL AND OPERATIONAL RESULTS

Following is a discussion of ARC's 2006 annual financial and operating results.

<TABLE>
<CAPTION>
FINANCIAL HIGHLIGHTS

=================================================================================================
(CDN$ millions, except per unit and volume data)       Q4 2006           Q4 2005       % Change
=================================================================================================
<S>                                                 <C>               <C>              <C>
Cash flow from operations                                760.6             639.5            19
Cash flow from operations per unit (1)                    3.72              3.35            11
Net income before future income tax and
  non-controlling interest                               379.6             364.1             4
Net income                                               460.1             356.9            29
Net income per unit (2)                                   2.28              1.90            20
Distributions per unit (3)                                2.40              1.99            21
Payout ratio per cent (4)                                   64                59             8
Average daily production (boe/d) (5)                    63,056            56,254            12
=================================================================================================
</TABLE>
(1)  Per unit amounts are based on weighted  average units plus units  issuable
     for exhangeable shares at year-end.
(2)  Based on net income  after  non-controlling  interest  divided by weighted
     average  trust units  excluding  trust  units  issuable  for  exchangeable
     shares.
(3)  Based on number of trust units outstanding at each cash distribution date.
(4)  Based on cash distributions divided by cash flow from operations.
(5)  Reported  production  amount is based on company  interest  before royalty
     burdens.  Where  applicable in this MD&A natural gas has been converted to
     barrels of oil  equivalent  ("boe")  based on 6 mcf:1 bbl. The boe rate is
     based on an energy equivalent  conversion  method primarily  applicable at
     the burner tip and does not represent a value equivalent at the well head.
     Use of boe in isolation may be misleading.

NET INCOME

Net income in 2006 was $460.1  million  ($2.28 per unit),  an  increase of $103
million  from  $356.9  million  ($1.90  per unit) in 2005 as a result of higher
production  volumes,  strong oil prices throughout 2006 and total hedging gains
on the commodity  hedging program of $24.7 million  compared to losses of $87.6
million in 2005. A  significant  future income tax recovery of $87.1 million in
2006,  attributed to the reduction in legislated  future  corporate  income tax
rates, also resulted in higher net income in 2006 relative to 2005.

CASH FLOW FROM OPERATIONS

Cash flow from operations increased by 19 per cent in 2006 to $761 million from
$640 million in 2005. The increase in 2006 cash flow was the result of a 12 per
cent  increase in  production  volumes,  partially  offset by lower natural gas
prices.  Cash flow was further increased by cash hedging gains of $29.3 million
in 2006  compared to a cash hedging loss of $87.6  million in 2005. A change in
the Trust's  product mix and the acquisition of properties with lower effective
royalty rates resulted in lower royalty  expense in 2006. The increases in 2006
cash flow were  somewhat  offset by higher  operating  costs,  higher  cash G&A
expenses and higher interest expense  attributed to increased debt levels.  Per
unit  cash flow from  operations  increased  11 per cent to $3.72 per unit from
$3.35 per unit in 2005.

Following is a summary of variances in cash flow from operations from 2005 to
2006:

<TABLE>
<CAPTION>
===============================================================================================================
                                                            ($ millions)    ($ per trust unit)   (% variance)
===============================================================================================================
<C>                                                         <C>              <C>                 <C>
2005 Cash flow from Operations                                  639.5               3.35
---------------------------------------------------------------------------------------------------------------
Volume variance                                                 140.9               0.74               22
Price variance                                                  (75.6)             (0.40)             (12)
Cash gains on commodity and foreign currency contracts (1)      116.8               0.61               18
Royalties                                                        13.0               0.07                2
Expenses:
   Transportation                                                (0.2)             (0.00)               -
   Operating (2)                                                (54.0)             (0.28)              (8)
   Cash G&A                                                      (8.9)             (0.05)              (1)
   Interest                                                     (14.8)             (0.08)              (2)
   Taxes                                                          3.6               0.02                1
   Realized foreign exchange gain                                 0.3               0.00                -
Weighted average trust units                                        -              (0.26)               -
---------------------------------------------------------------------------------------------------------------
2006 Cash flow from Operations                                  760.6               3.72               19
===============================================================================================================
</TABLE>
(1)  Represents cash gains (losses) on commodity and foreign currency contracts
     including  cash  settlements  on  termination  of  commodity  and  foreign
     currency contracts.
(2)  Excludes non-cash portion of LTIP expense recorded in operating costs.

<PAGE>

PRODUCTION

Production  volume  averaged  63,056 boe per day in 2006 compared to 56,254 boe
per  day in  2005.  The  Redwater  and  North  Pembina  Cardium  Unit  ("NPCU")
acquisitions  contributed  approximately  5,500  boe  per  day  (net)  in  2006
including 580 boe per day (net) of incremental  production on wells reactivated
during the year. With the acquisition of producing  properties in Manitoba,  an
incremental  785 boe per day of production came on-stream in the fourth quarter
of 2006.

The Trust's objective is to maintain annual production  through the drilling of
wells and other development activities. In fulfilling this objective, there may
be  fluctuations  in  production  depending  on the timing of new wells  coming
on-stream.  During 2006,  the Trust  drilled 294 gross wells (220 net wells) on
operated properties;  72 gross oil wells and 222 gross natural gas wells with a
99 per cent success rate.

The Trust expects that 2007 full year production will be  approximately  63,000
boe per day and that 275 gross  wells (225 net wells) will be drilled by ARC on
operated  properties with  participation in an additional 150 gross wells to be
drilled on the Trust's  non-operated  properties.  The Trust estimates that the
2007  drilling  program  will add 11,000 boe per day of  production  which will
offset production declines at existing properties.

===============================================================================
Production                                     2006           2005    % Change
===============================================================================
Crude oil (bbl/d)                              27,674         22,032      26
Heavy oil (bbl/d)                               1,368          1,250       9
Natural gas (mcf/d)                           179,067        173,800       3
NGL (bbl/d)                                     4,170          4,005       4
-------------------------------------------------------------------------------
Total production (boe/d) (1)                   63,056         56,254      12
-------------------------------------------------------------------------------
% Natural gas production                           47             51       -
% Crude oil and liquids production                 53             49       -
===============================================================================
(1)  Reported  production  for a period  may  include  minor  adjustments  from
     previous production periods.

Oil  production  increased  by 25 per cent to  29,042  boe per day in 2006 from
23,282  boe per  day in  2005.  The  increase  in oil  production  was  largely
attributed  to the Redwater  and NPCU  acquisitions  late in 2005.  The Trust's
weighting of oil and liquids  production  increased to 53 per cent in 2006 from
49 per cent in 2005 as the new volumes from  Redwater  and NPCU were  primarily
liquids.

Natural gas  production  increased  to 179.1 mmcf per day in 2006,  a three per
cent  increase  from the 173.8 mmcf per day  produced in 2005.  The majority of
this  increase was as a result of ARC's active 2006 internal  drilling  program
particularly in Northern and Central  Alberta.  In addition,  the Trust drilled
125 net operated  natural gas wells in  Southeastern  Alberta and  Southwestern
Saskatchewan  during  2006,  the  majority  of which were  drilled in the third
quarter and came on production during the fourth quarter.

The following table summarizes the Trust's production by core area:

<TABLE>
<CAPTION>
                                                    2006                                               2005
================================================================================================================================
Production                      Total         Oil         Gas           NGL         Total         Oil         Gas         NGL
Core Area (1)                  (boe/d)      (bbl/d)     (mmcf/d)      (bbl/d)      (boe/d)      (bbl/d)     (mmcf/d)    (bbl/d)
================================================================================================================================
<S>                          <C>          <C>          <C>           <C>          <C>         <C>          <C>         <C>
Central AB                      8,206        1,553        31.3         1,433         8,041       1,364        30.2       1,641
Northern AB & BC               18,897        6,194        67.6         1,452        18,286       6,026        65.3       1,381
Pembina & Redwater             13,950        9,453        20.0         1,157         7,953       4,166        17.7         832
S.E. AB & S.W. Sask.           10,743        1,071        58.0             9        11,298       1,499        58.7          15
S.E. Sask.                     11,260       10,771         2.2           119        10,676      10,227         1.9         136
--------------------------------------------------------------------------------------------------------------------------------
Total                          63,056       29,042       179.1         4,170        56,254      23,282       173.8       4,005
================================================================================================================================
</TABLE>
(1) Provincial references: AB is Alberta, BC is British Columbia, Sask. is
   Saskatchewan, S.E. is southeast, S.W. is southwest.

<PAGE>

COMMODITY PRICES PRIOR TO HEDGING

===============================================================================
Average Benchmark Prices                         2006        2005     % Change
===============================================================================
AECO gas ($/mcf) (1)                             6.98        8.45        (17)
WTI oil (US$/bbl) (2)                           66.25       56.61         17
USD/CAD foreign exchange rate                    0.88        0.83          6
WTI oil (CDN $/bbl)                             75.00       68.52          9
===============================================================================
(1)  Represents the AECO monthly posting.
(2)  WTI represents West Texas Intermediate posting as denominated in US$.

Oil  prices  reached  historic  highs in 2006  peaking at  US$77.03  per barrel
averaging  US$66.25  per barrel for the full year of 2006.  The strength of the
Canadian  dollar  served  to  partially   offset  the  impact  of  higher  U.S.
denominated oil prices.  The Trust's oil production  consists  predominantly of
light and medium  crude oil while  heavy oil  accounts  for less than three per
cent  of the  Trust's  liquids  production.  Overall  the  price  of WTI oil in
Canadian  dollars  increased  by nine per cent  over the  prior  year to $75.00
versus $68.52 in 2005.

Alberta  AECO Hub natural gas prices,  which are  commonly  used as an industry
reference,  averaged  $6.98 per mcf in 2006  compared to $8.45 per mcf in 2005.
Natural gas prices started the year at an historic high point of $12.11 per mcf
but  declined  dramatically  throughout  the second and third  quarters.  ARC's
realized gas price,  before hedging,  decreased by 22 per cent to $6.97 per mcf
compared to $8.96 per mcf in 2005.  ARC's realized gas price is based on prices
received at the various markets in which the Trust sells its natural gas. ARC's
natural gas sales  portfolio  consists of gas sales  priced at the AECO monthly
index,  the AECO daily spot market,  eastern and mid-west United States markets
and a portion to aggregators.

Prior to hedging  activities,  ARC's total realized  commodity price was $53.33
per boe in 2006, a six per cent decrease from the $56.54 per boe received prior
to hedging in 2005.

The following is a summary of realized prices:

===============================================================================
ARC Realized Prices Prior to Hedging                2006       2005   % Change
===============================================================================
Oil ($/bbl)                                        65.26      61.11       7
Natural gas ($/mcf)                                 6.97       8.96     (22)
NGL ($/bbl)                                        52.63      49.92       5
-------------------------------------------------------------------------------
Total commodity revenue before hedging ($/boe)     53.33      56.54      (6)
Other revenue ($/boe)                               0.13       0.21     (38)
Total revenue before hedging ($/boe)               53.46      56.75      (6)
===============================================================================

REVENUE

Revenue increased to a historical high of $1.2 billion in 2006. The increase in
revenue was  attributable  to higher  volumes and higher oil prices  which were
partially offset by lower natural gas prices.

A breakdown of revenue is as follows:

===============================================================================
Revenue ($ millions)                                2006       2005   % Change
===============================================================================
Oil revenue                                        691.8      519.3       33
Natural gas revenue                                455.7      568.7      (20)
NGL revenue                                         80.1       73.0       10
-------------------------------------------------------------------------------
Total commodity revenue                          1,227.6    1,161.0        6
-------------------------------------------------------------------------------
Other revenue                                        2.9        4.2      (31)
Total revenue                                    1,230.5    1,165.2        6
===============================================================================

RISK MANAGEMENT AND HEDGING ACTIVITIES

The Trust  continues to maintain a strong  hedging  mandate with an emphasis on
protecting cash flow and distributions to unitholders.

The Trust's  risk  management  activities  are  conducted  by an internal  Risk
Management  Committee,  based  upon  guidelines  approved  by the Board and the
following mandate:

o    protect unitholder return on investment;
o    provide protection for minimum monthly cash distributions to unitholders;
o    employ a portfolio  approach to risk  management by entering into a number
     of small positions that build upon each other;
o    participate  in commodity  price upturns to the greatest  extent  possible
     while limiting exposure to price downturns; and,
o    ensure  profitability  of specific  oil and gas  properties  that are more
     sensitive to changes in market conditions.

<PAGE>

To satisfy this  mandate,  the board of directors has approved that up to three
per cent of forecast  revenues may be spent on option  premiums on a go-forward
basis to achieve price protection and satisfy the risk management mandate while
limiting the risk exposure of hedged positions.

In 2006 ARC implemented the following  strategies to protect  distributions and
provide upside commodity price participation to the unitholder:

o    Protected power consumption with electricity swaps;
o    Protected natural gas prices with an energy equivalent swap to crude oil;
o    Protected  the 2005 Redwater  acquisitions  volume with US$55 floors via a
     3-way collar;
o    Protected  price  conversion of US$ denominated WTI crude oil with foreign
     exchange swaps;
o    Protected on average 44 per cent of natural gas production and 35 per cent
     of crude oil production for the year;
o    Protected as much as 62 per cent of natural gas production  volumes during
     the most vulnerable fall months; and,
o    Protected  natural gas and crude oil production  with a portfolio of floor
     and ceiling option contracts.

ARC uses a combination of puts and call options  otherwise  known as floors and
ceilings to protect budgeted  commodity prices. A floor or put option ensures a
minimum  selling  price  and a ceiling  or call  option  establishes  a maximum
selling price.  ARC employs a strategy of buying floors and offsetting the cost
of those  floors by selling  ceilings  at higher  prices or selling  additional
floors at lower prices. The net cost or premiums associated with the protection
that is put in place is viewed as an insurance  premium to ensure cash flow and
stability   of   distributions,   while   maintaining   strong   upside   price
participation.

By implementing these strategies ARC realized total cash hedging gains of $29.3
million in 2006 as  illustrated in detail in the "Gain or Loss on Commodity and
Foreign  Currency  Contracts"  section of this MD&A. In addition,  cash hedging
gains of $3.4 million on  electricity  hedges have been recorded as a reduction
of 2006 operating costs.

On a  forward-looking  basis ARC continues to put layers of protection in place
on both crude oil and natural gas. ARC has protection on  approximately  40 per
cent of oil  production  and 25 per cent of natural gas  production for 2007 as
shown in the following  table which  represents  ARC's positions in place as at
January 31, 2007.

<TABLE>
<CAPTION>
2007 HEDGE POSITIONS

as at January 31, 2007 (1) (2)                 Q1                        Q2                       Q3                       Q4
=================================================================================================================================
Crude Oil                       US$/bbl     bbl/day       US$/bbl      bbl/day      US$/bbl      bbl/day      US$/bbl    bbl/day
=================================================================================================================================
<S>                            <C>         <C>           <C>          <C>          <C>          <C>          <C>        <C>
Sold Call                         89.05       7,500         89.05        7,500        87.65        7,500        87.65      7,500
Bought Put                        63.42      13,656         63.46       13,000        61.67       12,000        61.67     12,000
Sold Put                          50.02      10,000         50.02       13,000        48.13       12,000        48.13     12,000
---------------------------------------------------------------------------------------------------------------------------------
Natural Gas                     CDN$/GJ      GJ/day       CDN$/GJ       GJ/day      CDN$/GJ       GJ/day      CDN$/GJ     GJ/day
---------------------------------------------------------------------------------------------------------------------------------
Sold Call                         10.89      93,566          8.39      113,028         8.89       50,000        10.58     30,839
Bought Put                         7.97      93,566          7.05      113,028         7.15       50,000         7.62     30,839
Sold Put                           5.50      10,000          5.15       50,000         5.15       50,000         5.15     16,848
---------------------------------------------------------------------------------------------------------------------------------
FX                              CAD/USD    $M/month       CAD/USD     $M/month      CAD/USD     $M/month      CAD/USD   $M/month
---------------------------------------------------------------------------------------------------------------------------------
Bought Put                       1.1321         2.4        1.1321          2.4       1.1321          2.4       1.1321        2.4
Sold Put                         1.0990         2.0        1.0990          2.0       1.0990          2.0       1.0990        2.0
Swap                             1.1387        16.6        1.1387         16.6       1.1387         16.6       1.1387       16.6
=================================================================================================================================
</TABLE>
(1)  Note that the prices and  volumes  noted  above  represents  averages  for
     several  contracts  and the  average  price for the  portfolio  of options
     listed  above  does not have the same  payoff  profile  as the  individual
     option  contracts.  Viewing  the  average  price of a group of  options is
     purely for indicative purposes. The natural gas price shown translates all
     NYMEX  positions  to an AECO  equivalent  price.  In addition to positions
     shown here, ARC has entered into additional basis positions.
(2)  Please  refer  to the  Trust's  website  at  www.arcenergytrust.com  under
     "Hedging Program" within the "Investor  Relations"  section for details on
     the Trust's hedging positions as of January 31, 2007.

The above table should be  interpreted  as follows  using the 2007 Q1 Crude Oil
Hedges as an example. For oil, the Trust has hedged 13,656 barrels per day at a
minimum  average price of US$63.42 and  participates  in prices up to a maximum
average of  US$89.05 on 7,500  barrels  per day with no limit on the  remaining
6,156 barrels per day hedged.  Finally, ARC's average protected price of $63.42
reduces penny for penny at an average price below $50.02 on 10,000  barrels per
day.

During 2006 ARC entered  into  "basis"  natural  gas  contracts  to lock in the
difference  between the Henry Hub index and the AECO monthly index. This set of
transactions  diversifies  ARC's  price  exposure  from the  AECO  basin to the
broader North  American  market,  thus reducing  ARC's  sensitivity to regional
market events.  Basis swaps are negotiated in terms of a fixed price in US$ per
mmbtu that is deducted from the NYMEX natural gas price. For the period January
1, 2007 through March 2007,  the Trust locked in the basis at US$1.31 per mmbtu
on an average  volume of 40,000 mcf per day and ARC has an average  basis price
of US$1.08 per mmbtu on an average volume of 50 mmcf per day of natural gas for
the period of April 2007 through October 2010.

<PAGE>

In addition to these positions the Trust has fixed the price of electricity for
a portion of its power  consumption at average prices between $59.33 and $64.63
through  2010 to mitigate  the risk  associated  with  fluctuating  electricity
prices which have a large impact on operating  costs. A significant  portion of
the Trust's power usage is subject to the deregulated  Alberta Power Pool price
which was extremely  volatile during 2006 and ranged from a record high monthly
average price of $174.09 mw/h to a low of $42.87 mw/h.  The  electricity  hedge
represents  approximately 69 per cent of the Trust's Alberta power  consumption
at operated properties.

The Trust  considers  its risk  management  contracts to be effective  economic
hedges as they meet the objectives of the Trust's risk management  mandate.  In
order to  mitigate  credit  risk,  the Trust  executes  commodity  and  foreign
currency  hedging  risk  management  with  financially  sound,   credit  worthy
counterparties.  All contracts  require approval of the Trust's Risk Management
Committee prior to execution.  Deferred  premiums payable will be recorded as a
realized  cash  hedging  loss when  payment is made in a future  period.  These
premiums  may be  partially  offset if ARC sells any  short-term  options.  The
Trust's  oil  contracts  are  based on the WTI index  and the  majority  of the
Trust's natural gas contracts are based on the AECO monthly index.

For a complete  summary of the Trust's  oil,  natural gas and foreign  exchange
hedges,  please  refer to  "Hedging  Program"  under the  "Investor  Relations"
section of the Trust's website at www.arcenergytrust.com.

GAIN OR LOSS ON COMMODITY AND FOREIGN CURRENCY CONTRACTS

Gain or loss on commodity and foreign currency  contracts comprise realized and
unrealized gains or losses on commodity and foreign currency  contracts that do
not meet the accounting  definition of the  requirements of an effective hedge,
even though the Trust considers all commodity and foreign currency contracts to
be effective economic hedges.  Accordingly,  gains and losses on such contracts
are shown as a separate category in the statement of income.

The Trust  recorded a realized  cash gain on  commodity  and  foreign  currency
contracts  of $29.3  million  in 2006 as  compared  to a loss of $87.6  million
recorded in 2005.  The majority of the 2006 cash gains were  attributed  to the
natural gas hedges whereby the Trust utilized a variety of contracts to lock in
the minimum  price on natural  gas. As gas prices  declined  subsequent  to the
first quarter, the Trust realized significant gains on the contracts.

The  following is a summary of the total gain (loss) on  commodity  and foreign
currency contracts for 2006:

<TABLE>
<CAPTION>
Commodity and Foreign Currency Contracts
---------------------------------------------------------------------------------------------------------------
                                                    Crude Oil      Natural      Foreign        2006      2005
($ millions)                                        & Liquids      Gas          Currency       Total     Total
---------------------------------------------------------------------------------------------------------------
<S>                                                 <C>            <C>          <C>           <C>        <C>
Realized cash gain (loss) on contracts (1)            (7.7)         29.7          7.3           29.3     (87.6)
Unrealized gain (loss) on contracts (2)                6.2          (4.1)        (6.7)          (4.6)        -
---------------------------------------------------------------------------------------------------------------
Total gain (loss) on commodity
   and foreign currency contracts                     (1.5)         25.6          0.6           24.7     (87.6)
===============================================================================================================
</TABLE>
(1)  Realized  cash gains and  losses  represent  actual  cash  settlements  or
     receipts under the respective contracts.
(2)  The  unrealized  (loss) gain on  contracts  represents  the change in fair
     value of the contracts during the period.

<PAGE>

OPERATING NETBACKS

The  Trust's  operating  netback,  after  realized  hedging  gains  or  losses,
increased  eight per cent to $35.95 per boe in 2006  compared to $33.40 per boe
in 2005. The increase in netbacks in 2006 is primarily due to higher oil prices
in 2006,  a decrease  in  royalties,  and cash  hedging  gains of $1.27 per boe
compared  to losses of $4.26 per boe in 2005.  A decline in natural  gas prices
and higher  operating  costs  partially  offset the  higher  revenue  and lower
royalties.

The components of operating netbacks are shown below:

<TABLE>
<CAPTION>
NETBACKS
===========================================================================================================================
                                          Crude Oil       Heavy Oil       Gas          NGL       2006 Total    2005 Total
($ per boe)                                ($/bbl)         ($/bbl)      ($/mcf)      ($/bbl)       ($/boe)      ($/boe)
===========================================================================================================================
<S>                                      <C>             <C>           <C>         <C>           <C>          <C>
Weighted average sales price                66.16           46.90         6.97        52.63         53.33        56.54
Other revenue                                  -                -            -           -           0.13         0.21
---------------------------------------------------------------------------------------------------------------------------
Total revenue                               66.16           46.90         6.97        52.63         53.46        56.75
Royalties                                  (10.80)          (4.86)       (1.37)      (14.08)        (9.66)      (11.46)
Transportation                              (0.14)          (0.86)       (0.19)           -         (0.63)       (0.70)
Operating costs (1)                        (11.51)         (10.63)       (0.96)       (7.49)        (8.49)       (6.93)
---------------------------------------------------------------------------------------------------------------------------
Netback prior to hedging                    43.71           30.55         4.45        31.06         34.68        37.66
Realized gain (loss) on commodity
   and foreign currency contracts           (0.05)              -         0.45            -          1.27        (4.26)
---------------------------------------------------------------------------------------------------------------------------
Netback after hedging                       43.66           30.55         4.90        31.06         35.95        33.40
===========================================================================================================================
</TABLE>
(1) Operating expenses are composed of direct costs incurred to operate oil and
   gas wells. A number of assumptions have been made in allocating these costs
   between oil, heavy oil, natural gas and natural gas liquids production.

Royalties  decreased  to $9.66 per boe in 2006  compared  to $11.46  per boe in
2005.  Royalties  as a  percentage  of  pre-hedged  commodity  revenue  net  of
transportation  costs decreased to 18 per cent compared to 20 per cent in 2005.
The decrease in royalties is due to a lower effective royalty rate in 2006 as a
result of the increased oil weighting of the Trust's  production  following the
2005 acquisitions and royalty concessions  received on certain British Columbia
natural gas properties.  In addition, the Redwater and NPCU properties acquired
in 2005 carried a significantly  lower effective  royalty rate than the Trust's
existing properties due to the royalty structure of the properties.

Operating  costs  increased to $8.49 per boe compared to $6.93 per boe in 2005.
The  acquisition of the Redwater and NPCU  properties,  with operating costs of
approximately $22 per boe in 2006, contributed to a large portion of the 23 per
cent increase in operating  costs.  However,  the Redwater and NPCU  properties
also   contribute  high  netbacks  of  $40.60  per  boe  and  $40.19  per  boe,
respectively,  due to the premium oil quality and low royalty  regime.  Despite
reductions  in  natural  gas  prices  during  2006,   the  industry  was  still
experiencing increasing costs for services,  supplies,  materials,  electricity
and  labour   throughout  2006.  In  particular,   areas  in  northern  Alberta
experienced  significant cost increases for services,  materials and labour. In
addition,  the cost of electricity in Alberta was extremely volatile during the
second  half of 2006 with daily  average  prices  ranging  from  $16.49 mw/h to
$576.10 mw/h.  Approximately  69 per cent of the Trust's  electricity  usage on
Alberta operated  properties was hedged at  approximately  $63 mw/h whereby the
Trust was partially  protected  from the increases in  electricity  costs.  The
electricity  hedge resulted in a $0.15 per boe reduction in operating  costs in
2006.

Transportation costs decreased 10 per cent to $0.63 per boe in 2006 compared to
$0.70 per boe in 2005.  This is a result of the increased  percentage of oil in
the Trust's  production  mix as oil generally has a lower  transportation  cost
than  natural gas as a majority of the  Trust's oil  production  is sold at the
plantgate.

In 2007 it is expected that operating costs will increase by approximately five
per cent to $8.95  per boe  primarily  due to costs  associated  with our newly
acquired  properties and the additional  11,000 boe per day of 2007 development
production  volumes.  The Trust expects that the industry cost  pressures  will
ease  slightly  in 2007  due to the  moderation  in  industry  activity  levels
experienced late in 2006.

<PAGE>

GENERAL AND ADMINISTRATIVE EXPENSES AND TRUST UNIT INCENTIVE COMPENSATION

Cash G&A net of overhead  recoveries  on operated  properties  increased 32 per
cent to $36.3 million in 2006 from $27.4 million in 2005. Increases in cash G&A
expenses for 2006 were due to increased staff levels, higher compensation costs
and the  nature  of ARC's  long-term  incentive  program.  As a  result  of the
unprecedented  levels of activity for ARC and for the industry as a whole,  the
costs  associated  with  hiring,   compensating  and  retaining  employees  and
consultants  have  risen.  The  increase in G&A costs was  partially  offset by
higher overhead  recoveries  attributed to high levels of capital and operating
activity throughout 2006 and as a result of incremental overhead charged on new
and existing operated properties.  On a per boe basis, cash G&A costs increased
18 per cent to $1.58 per boe from $1.34 per boe as a result of higher  cash G&A
costs partially offset by increased production volume.

The Trust paid out $5.2 million  under the whole unit plan in 2006  compared to
$1.6  million in 2005  ($3.5  million  and $1.1  million  of the  payouts  were
allocated to G&A in 2006 and 2005, respectively, and the remainder to operating
costs and capital projects). The higher cash payment in 2006 is attributed to a
higher  unit price  upon  vesting  in April and  October  of each year,  higher
distributions  and having two years of awards  vesting in 2006  compared to one
year of awards  in 2005.  The next cash  payment  under the Whole  Unit Plan is
scheduled to occur in April 2007.

The  following  is a  breakdown  of G&A and trust unit  incentive  compensation
expense:

G&A AND TRUST UNIT INCENTIVE COMPENSATION EXPENSE
===============================================================================
($ millions except per boe)                         2006       2005    % Change
===============================================================================
G&A expenses                                         45.8      35.0        31
Operating recoveries                                (12.9)     (8.7)       48
-------------------------------------------------------------------------------
Cash G&A expenses before Whole Unit Plan             32.9      26.3        25
Cash Expense - Whole Unit Plan                        3.5       1.1       218
-------------------------------------------------------------------------------
Cash G&A expenses including Whole Unit Plan          36.4      27.4        32
-------------------------------------------------------------------------------
Accrued compensation - Rights Plan                    2.5       6.5       (62)
Accrued compensation - Whole Unit Plan                8.2       8.8        (7)
-------------------------------------------------------------------------------
Total G&A and trust unit incentive
  compensation expense                               47.1      42.7        10
-------------------------------------------------------------------------------
Cash G&A expenses per boe                            1.58      1.34        18
Total G&A and trust unit incentive compensation
  expense per boe                                    2.05      2.08        (1)
===============================================================================

A non-cash trust unit incentive  compensation  expense ("non-cash  compensation
expense") of $10.7  million  ($0.47 per boe) was  recorded in 2006  compared to
$15.3  million  ($0.74  per boe) in  2005.  This  non-cash  amount  relates  to
estimated costs of the Trust Unit Incentive Rights Plan ("Rights Plan") and the
Whole Trust Unit  Incentive  Plan  ("Whole  Unit Plan") to December  31,  2006.
Despite a higher number of units  outstanding under the plan in 2006, there was
a decrease in the value of the Whole Unit Plan and a reduction  in the non-cash
expense  due  to the  decline  in  trust  unit  prices  following  the  Federal
Government's  proposed  Trust  taxation  announcement  in the fourth quarter of
2006.

RIGHTS PLAN

The Rights Plan  provides  employees,  officers and  independent  directors the
right to purchase units at a specified  price. The rights have a five year term
and vest equally over three years. The exercise price of the rights is adjusted
downwards from time-to-time by the amount that distributions to unitholders, in
any  calendar  quarter  exceeds  2.5 per cent of the  Trust's net book value of
property,  plant and  equipment.  The rights plan was  replaced by a Whole Unit
Plan  during  2004 after  which no further  rights  under the rights  plan were
issued.  During 2006,  one million  rights were  exercised or cancelled and 0.4
million rights  remained  outstanding as at December 31, 2006. Of the remaining
rights outstanding, 6,000 will vest in March 2007 and compensation expense will
be recorded until that time. All other rights were fully vested and expensed as
of December 31, 2006.

The decrease in compensation  expense for the rights plan in 2006 is due to the
majority of rights having vested early in 2006 and compensation expense is only
recorded up to vesting date.

<PAGE>

WHOLE TRUST UNIT INCENTIVE PLAN ("WHOLE UNIT PLAN")

In March 2004, the Board of Directors approved a new Whole Unit Plan to replace
the Rights Plan for new awards granted subsequent to the first quarter of 2004.
The new Whole Unit Plan results in employees, officers and directors (the "plan
participants")  receiving  cash  compensation  in  relation  to the  value of a
specified  number  of  underlying  units.  The  Whole  Unit  Plan  consists  of
Restricted Trust Units ("RTUs") for which the number of units is fixed and will
vest over a period of three  years and  Performance  Trust Units  ("PTUs")  for
which the number of units is variable and will vest at the end of three years.

Upon vesting,  the plan participant is entitled to receive a cash payment based
on the fair value of the underlying trust units plus accrued distributions. The
cash  compensation  issued  upon  vesting  of the  PTUs is  dependent  upon the
performance of the Trust compared to its peers and indicated by the performance
multiplier.  The performance  multiplier is based on the percentile rank of the
Trust's  total  unitholder  return  compared  to its  peers.  Total  return  is
calculated  as the sum of the  change in the  market  price of the units in the
period  plus  the  amount  of  distributions  in the  period.  The  performance
multiplier ranges from zero, if ARC's performance ranks in the bottom quartile,
to two for top quartile performance.

The  following  table  shows  the  changes  during  the  year of RTUs  and PTUs
outstanding:

<TABLE>
<CAPTION>
WHOLE UNIT PLAN
=======================================================================================================
                                                          Number of         Number of      Total
(units in thousands and $ millions except per unit)         RTUs              PTUs      RTUs and PTUs
======================================================================================================
<S>                                                     <C>               <C>           <C>
Balance, beginning of period                                 479               391           870
Granted in the period                                        373               303           676
Vested in the period                                        (180)                -          (180)
Forfeited in the period                                      (24)              (11)          (35)
------------------------------------------------------------------------------------------------------
Balance, end of period (1)                                   648               683         1,331
------------------------------------------------------------------------------------------------------
Estimated distributions to vesting date (2)                  168               222           390
Estimated units upon vesting after distributions             816               905         1,721
------------------------------------------------------------------------------------------------------
Performance multiplier (3)                                     -               2.0
------------------------------------------------------------------------------------------------------
Estimated total units upon vesting                           816             1,810         2,626
Trust unit price at December 31, 2006                   $  22.30          $  22.30      $  22.30
Estimated total value upon vesting                      $   18.2          $   40.4      $   58.6
======================================================================================================
</TABLE>
(1)  Based on  underlying  units  before  performance  multiplier  and  accrued
     distributions.
(2) Represents estimated additional units to be issued equivalent to estimated
   distributions accruing to vesting date.

(3) The performance multiplier only applies to PTUs and approximated 2.0 at
   December 31, 2006. The performance multiplier is assessed each period end
   based on actual results of the Trust relative to its peers.

The value  associated  with the RTUs and PTUs is expensed in the  statement  of
income over the vesting period with the expense amount being  determined by the
unit  price,  the number of PTUs to be issued on  vesting,  and  distributions.
Therefore,  the expense  recorded in the  statement of income  fluctuates  over
time.

As at  December  31,  2006,  the  PTUs  outstanding  were  assessed  to  have a
percentile  rank  equal  or  greater  than  75  and  thus  were  valued  with a
performance  multiplier  of 2.0.  Below is a  summary  of the  range of  future
expected  payments  under  the  Whole  Unit Plan  based on  variability  of the
performance multiplier:

<PAGE>

VALUE OF WHOLE UNIT PLAN AS AT DECEMBER 31, 2006

                                                     Performance Multiplier
===============================================================================
(units thousands and $ millions except per unit)      -         1.0        2.0
===============================================================================
Estimated trust units to vest
-------------------------------------------------------------------------------
   RTUs                                             816         816        816
   PTUs                                               -         905      1,810
-------------------------------------------------------------------------------
Total units (1)                                     816       1,721      2,626
-------------------------------------------------------------------------------
   Trust unit price (2)                           22.30       22.30      22.30
   Trust unit distributions per month (2)          0.20        0.20       0.20
-------------------------------------------------------------------------------
Value of Whole Unit Plan upon vesting              18.2        38.8       58.6
-------------------------------------------------------------------------------
   Officers                                         2.1        11.6       20.9
   Directors                                        1.4         1.4        1.4
   Staff                                           14.7        25.8       36.3
-------------------------------------------------------------------------------
Total payments under Whole Unit Plan (3)           18.2        38.8       58.6
-------------------------------------------------------------------------------
   2007                                             7.8        11.2       14.6
   2008                                             6.7        14.9       23.1
   2009                                             3.7        12.7       20.9
===============================================================================
(1)  Includes additional estimated units to be issued for accrued distributions
     to vesting date.
(2)  Values will  fluctuate  over the vesting period based on the volatility of
     the underlying  trust unit price and distribution  levels.  Assumed future
     trust unit price of $22.30 per trust unit and  distributions  of $0.20 per
     unit per month based on current levels.
(3)  Upon  vesting,  a cash  payment  is made  equivalent  to the  value of the
     underlying  trust units. The payment is made on vesting dates in April and
     October of each year and at that time is  reflected as a reduction of cash
     flow from operations.

Due to the  variability  in the  future  payments  under  the  plan,  the Trust
estimates  that  $18.2  million  to $58.6  million  will be paid out from  2007
through 2009 based on the current trust unit price,  distribution  levels and a
performance multiplier ranging from zero to two.

INTEREST EXPENSE

Interest expense  increased to $31.8 million in 2006 from $16.9 million in 2005
due to an increase in short-term  interest rates, and higher debt balances as a
result of the Trust's acquisitions  activity which was funded $125 million with
debt.  As  at  December  31,  2006,  the  Trust  had  $687.1  million  of  debt
outstanding,  of which $261  million  was fixed at a weighted  average  rate of
5.056 per cent and $426.1  million was floating at current  market rates plus a
credit spread of 65 basis points.  Seventy-one  per cent of the Trust's debt is
denominated in U.S. dollars.

The  following is a summary of the debt  balance and interest  expense for 2006
and 2005:

INTEREST EXPENSE
===============================================================================
($ millions)                                       2006       2005    % Change
===============================================================================
Year end debt balance (1)                         687.1      526.6        30
   Fixed rate debt                                261.0      268.2        (3)
   Floating rate debt                             426.1      258.4        65
-------------------------------------------------------------------------------
Interest expense before interest rate swaps (2)    31.4       17.4        80
Loss (gain) on interest rate hedge                  0.4       (0.5)      180
-------------------------------------------------------------------------------
Net interest expense                               31.8       16.9        88
=========================================================================== ===
(1)  Includes both long-term and current portions of debt.
(2)  The interest rate swap was designated as an effective hedge for accounting
     purposes  whereby  actual  realized  gains and losses  are netted  against
     interest expense.

FOREIGN EXCHANGE GAINS AND LOSSES

The Trust recorded a loss of $4.2 million  ($0.18 per boe) on foreign  exchange
transactions  compared to a gain of $6.4 million ($0.31 per boe) in 2005. These
amounts include both realized and unrealized foreign exchange gains and losses.
Unrealized  foreign  exchange  gains and losses are due to  revaluation of U.S.
denominated  debt balances.  The  volatility of the Canadian  dollar during the
reporting period has a direct impact on the unrealized component of the foreign
exchange gain or loss. The unrealized gain/loss impacts net income but does not
impact cash flow as it is a non-cash amount. Realized foreign exchange gains or
losses arise from U.S. denominated transactions such as interest payments, debt
repayments and hedging settlements.

Included in the 2006 realized  foreign exchange gain was a gain of $2.6 million
realized upon repayment of US$6 million of debt in 2006. The debt was issued in
2002  when  the  USD/CAD  foreign  exchange  rate  was  approximately  0.64 and
strengthened  considerably  to 0.88 on repayment in 2006.  The 2006  unrealized
foreign  exchange  loss of $7.1  million  was  due to the  revaluation  of U.S.
denominated debt balances  associated with the weakening of the Canadian dollar
relative to the U.S. dollar in 2006.

<PAGE>

TAXES

In 2006, a future  income tax recovery of $87.1  million was included in income
compared to a $1.6 million  expense in 2005.  The  significant  increase in the
future income tax recovery in 2006 was due to the  legislated  reduction in the
future  corporate  income tax rates in the second  quarter of 2006  whereby the
Trust's  expected  future income tax rate  decreased to 29.4 per cent from 33.7
per cent prior to the rate reductions.

Acquisitions  completed in 2006 resulted in the Trust recording a future income
tax liability of $5.4 million due to the  difference  between the tax basis and
the fair value assigned to the acquired assets.  The amount of tax pools versus
asset value is one of the parameters  that impacts the Trust's  acquisition bid
levels.

At December 31, 2006 the Trust's subsidiaries had tax pools of approximately $1
billion.  The tax pools  consist of $903  million of  tangible  and  intangible
capital assets, $18.2 million of non-capital loss carryforwards which expire at
various  periods to 2026, and $110 million for other tax pools.  In addition to
the above  tax basis for the  Trust's  subsidiaries,  the Trust  itself  had an
approximate tax basis of $545.1 million as at December 31, 2006.

On October 31,  2006,  the Federal  Government  announced  the Trust  taxation.
Currently,  distributions  paid to unitholders,  other than returns of capital,
are claimed as a deduction by the Trust in arriving at taxable  income  whereby
tax is  eliminated  at the  Trust  level  and is paid by the  unitholders.  The
proposals  would result in a two-tiered  tax  structure  whereby  distributions
would first be subject to a 31.5 per cent tax at the Trust level  commencing in
2011, and then unitholders would be subject to tax on the distribution as if it
were a taxable dividend paid by a taxable Canadian corporation. If enacted, the
proposals  would  apply to the Trust  effective  January 1, 2011.  The Trust is
currently  assessing  various   alternatives  with  respect  to  the  potential
implications of the tax proposals,  however until the legislation is enacted in
final form,  the Trust will not arrive at a final  conclusion  with  respect to
future Trust structure and  implications to the Trust. As the tax proposals had
not yet been  substantively  enacted as of December 31, 2006, the  consolidated
financial statements do not reflect the impact of the proposed taxation.

The corporate income tax rate applicable to 2006 is 34.5 per cent,  however ARC
does not  anticipate  any  material  cash income  taxes will be paid for fiscal
2006. Due to the Trust's structure,  currently,  both income tax and future tax
liabilities are passed on to the unitholders by means of royalty  payments made
between ARC Resources and the Trust.

Capital taxes were eliminated effective January 1, 2006 pursuant to the Federal
Government budget of May 2, 2006.

DEPLETION, DEPRECIATION AND ACCRETION OF ASSET RETIREMENT OBLIGATION

The depletion, depreciation and accretion ("DD&A") rate increased to $15.64 per
boe in 2006 from  $12.88 per boe in 2005.  The  higher  DD&A rate is due to the
Redwater  and NPCU  acquisitions  in the  fourth  quarter of 2005 for which the
Trust recorded a higher proportionate cost per barrel of proved reserves of the
acquired operations compared to the existing ARC properties.  In addition,  the
Trust completed net  acquisitions in 2006 for $131.8 million plus an additional
$5.4 future income tax liability  recorded on  acquisition,  both  acquisitions
were at a higher proportionate cost per barrel of proved reserves than existing
ARC  properties.  Accretion  expense was also higher in 2006 as a result of the
higher asset retirement  obligation recorded late in 2005 primarily  attributed
to the acquired Redwater and NPCU properties.

A breakdown of the DD&A rate is a follows:

DD&A RATE
===============================================================================
($ millions except per boe amounts)                 2006       2005    % Change
===============================================================================
Depletion of oil & gas assets (1)                  348.9      259.3        35
Accretion of asset retirement obligation (2)        11.1        5.2       113
-------------------------------------------------------------------------------
Total DD&A                                         360.0      264.5        36
DD&A rate per boe                                  15.64       12.88       21
===============================================================================
(1)  Includes  depletion  of the  capitalized  portion of the asset  retirement
     obligation  that was  capitalized  to the  property,  plant and  equipment
     ("PP&E") balance and is being depleted over the life of the reserves.
(2)  Represents the accretion expense on the asset retirement obligation during
     the year.

The  costs  subject  to  depletion  included  $61.3  million  relating  to  the
capitalized portion of the asset retirement  obligation as at December 31, 2006
($61.9 million as at December 31, 2005), net of accumulated depletion.

GOODWILL

The goodwill  balance of $157.6 million arose as a result of the acquisition of
Star in 2003. The goodwill  balance was determined based on the excess of total
consideration  paid plus the future income tax liability less the fair value of
the assets for accounting purposes acquired in the transaction.

Accounting  standards  require  that  the  goodwill  balance  be  assessed  for
impairment  at least  annually  or more  frequently  if  events or  changes  in
circumstances  indicate  that  the  balance  might  be  impaired.  If  such  an
impairment  exists,  it would be  charged  to income in the period in which the
impairment  occurs.  The  Trust  has  determined  that  there  was no  goodwill
impairment as of December 31, 2006.

<PAGE>

CAPITAL EXPENDITURES AND NET ACQUISITIONS

Total capital expenditures,  excluding  acquisitions and dispositions,  totaled
$364.5  million in 2006  compared  to $268.8  million in 2005.  This amount was
incurred on drilling and  completions,  geological,  geophysical and facilities
expenditures, and the purchase of undeveloped acreage. The significant increase
in 2006 capital  expenditures  is reflective of the Trust's higher  production,
larger  asset  base  and the  higher  cost  to  replace  production  as well as
increased spending on undeveloped land.

In  addition  to capital  expenditures  on  development  activities,  the Trust
completed  net  property  acquisitions  of  $115.2  million  in 2006.  The most
significant  property  acquisition  was the  purchase  of  Manitoba  properties
accounting  for 785 boe per day of oil  production and 3.4 mmboe of proved plus
probable  reserves  for cash  consideration  of $74  million.  The  Trust  also
completed one minor corporate acquisition for consideration of $16.6 million in
2006.

During the year,  the Trust drilled 294 gross wells (220 net wells) on operated
properties;  consisting  of 72 gross oil wells and 222 gross  natural gas wells
most of which were  shallow  gas wells with a success  rate of 99 per cent.  In
addition,  the Trust  participated in 441 gross wells (44 net wells) drilled by
other operators.

Proved plus probable oil and gas reserves were effectively  maintained at 286.1
mmboe at year end 2006 as a result  of the  Trust's  2006  capital  expenditure
program and property and corporate acquisitions.

A breakdown of capital expenditures and net acquisitions is shown below:

CAPITAL EXPENDITURES
===============================================================================
($ millions)                                         2006      2005   % Change
===============================================================================
Geological and geophysical                           11.4        9.2      24
Drilling and completions                            240.5      191.8      25
Plant and facilities                                 77.6       55.0      41
Undeveloped land                                     32.4        9.1     256
Other capital                                         2.6        3.7     (30)
-------------------------------------------------------------------------------
Total capital expenditures                          364.5      268.8      36
-------------------------------------------------------------------------------
Producing property acquisitions (1)                 124.0      111.3      11
Producing property dispositions (1)                  (8.8)     (20.0)    (57)
Corporate acquisitions (2)                           16.6      505.0    (967)
-------------------------------------------------------------------------------
Total capital expenditures and net acquisitions     496.3      865.1    (426)
===============================================================================
(1)  Value is net of post-closing adjustments.
(2)  Represents total consideration for the transactions, including fees but is
     prior  to the  related  future  income  tax  liability,  asset  retirement
     obligation and working capital assumed on acquisition.

Approximately  72 per cent of the $364.5 million  capital  program was financed
with  cash  flow  from  operations  in 2006  compared  to 95 per  cent in 2005.
Property and corporate acquisitions were financed through a combination of debt
and  proceeds  from the 2006  distribution  reinvestment  program and  employee
rights plan.

<PAGE>

<TABLE>
<CAPTION>
SOURCE OF FUNDING OF CAPITAL EXPENDITURES AND NET ACQUISITIONS

==============================================================================================================================
                                                       2006                                          2005
                                     Development        Net            Total       Development        Net           Total
($ millions)                           Capital      Acquisitions   Expenditures      Capital     Acquisitions    Expenditures
==============================================================================================================================
<S>                                  <C>            <C>            <C>             <C>           <C>             <C>
Expenditures                           364.5           131.8           496.3          268.8          596.3            865.1
------------------------------------------------------------------------------------------------------------------------------
Per cent funded by:
Cash flow                                 72%              -              53%            95%             -               30%
Proceeds from DRIP and Rights Plan        28%              5%             22%             5%             9%               8%
Proceeds from equity offering              -               -               -              -             40%              28%
Debt -                                    95%             25%              -             51%            34%
                                         100%            100%            100%           100%           100%             100%
==============================================================================================================================
</TABLE>

ARC  expects to  undertake  significant  development  activities  again in 2007
resulting in a $360 million capital budget.  The Trust plans to drill 275 gross
wells (225 net wells) on operated  properties in 2007, allocate $6.5 million to
Enhanced Oil Recovery  initiatives  such as carbon dioxide  ("CO2")  injection,
continue to research  Natural Gas from Coal ("NGC")  opportunities  and develop
the recently acquired Manitoba properties.

LONG-TERM INVESTMENT

During the second quarter of 2006,  the Trust made a $20 million  investment in
the shares of a private  company  that is  involved in the  acquisition  of oil
sands leases with development potential. At year end, the Trust holds less than
a two per cent interest in the company and has the intent of holding the shares
for investment purposes.

The investment in the shares of the private company has been considered to be a
related party transaction due to common directorships of the Trust, the private
company  and the  manager of a private  equity  fund that  holds  shares in the
private company. In addition,  certain directors and officers of the Trust have
minor  direct and indirect  shareholdings  in the private  company.  All of the
interested  directors  declared  their interest and the investment was approved
unanimously  by the  directors  of  the  Trust  not  including  the  interested
directors.  The $20  million  investment  was  part of a $325  million  private
placement of the private company.

ASSET RETIREMENT OBLIGATION AND RECLAMATION FUND

At December 31, 2006,  the Trust has  recorded an Asset  Retirement  Obligation
("ARO") of $177.3  million  ($165.1  million at December  31,  2005) for future
abandonment  and  reclamation  of the  Trust's  properties.  The ARO  increased
slightly  in 2006 as a result of wells  drilled  in the year and  property  and
corporate  acquisitions  completed in 2006. The ARO further  increased by $11.1
million for accretion expense in 2006 ($5.2 million in 2005) and was reduced by
$10.6  million  ($4.9  million  in 2005) for  actual  abandonment  expenditures
incurred in 2005. The Trust did not record a gain or loss on actual abandonment
expenditures  incurred as the costs closely  approximated  the liability  value
included in the ARO.

As a result of the Redwater  acquisition  in December  2005, the Trust set up a
new restricted  reclamation  fund (the "Redwater  Fund") in 2006 to fund future
abandonment obligations attributed to the Redwater properties.  The Trust makes
annual  contributions  to the Redwater  fund and may utilize the funds only for
abandonment  activities  for the  Redwater  property.  With the addition of the
Redwater  Fund,  the Trust now maintains two  reclamation  funds which together
held $30.9  million of money market  instruments  at December 31, 2006.  Future
contributions for the two funds will vary over time in order to provide for the
total  estimated  future  abandonment  and  reclamation  costs  that  are to be
incurred  upon  abandonment  of the  Trust's  properties.  The Trust  currently
estimates  that $230 million will be  contributed to the funds over the next 50
years to provide for future abandonment and reclamation costs.

In total, ARC contributed  $12.1 million cash to its reclamation  funds in 2006
($6 million in 2005) and earned  interest of $1 million  ($0.8 million in 2005)
on the fund  balances.  The increase in funding is  attributed  to the Redwater
fund.  The  fund  balances  were  reduced  by  $5.7  million  for   cash-funded
abandonment expenditures 2006 ($4.6 million in 2005).

<PAGE>

CAPITALIZATION, FINANCIAL RESOURCES AND LIQUIDITY

A breakdown of the Trust's  capital  structure is as follows as at December 31,
2006 and 2005:

===============================================================================
Capital Structure and Liquidity
($ millions except per unit and per cent amounts)            2006        2005
===============================================================================
Revolving credit facilities                                 426.1       258.5
Senior secured notes                                        261.0       268.2
Working capital deficit excluding short-term debt (1)        52.0        51.4
-------------------------------------------------------------------------------
Net debt obligations                                        739.1       578.1
-------------------------------------------------------------------------------
Units outstanding and issuable for exchangeable
  shares (thousands)                                        207.2       202.0
Market price per unit at end of year                        22.30       26.49
Market value of units and exchangeable shares             4,620.0     5,352.0
-------------------------------------------------------------------------------
Total capitalization (2)                                  5,359.1     5,930.1
-------------------------------------------------------------------------------
Net debt as a percentage of total capitalization             13.8%       9.7%
Net debt obligations                                        739.1       578.1
Cash flow from operations                                   760.6       639.5
Net debt to cash flow                                         1.0         0.9
===============================================================================
(1)  The working  capital  deficit  excludes  the balances  for  commodity  and
     foreign currency contracts.
(2)  Total  capitalization as presented does not have any standardized  meaning
     prescribed by Canadian  GAAP and  therefore it may not be comparable  with
     the   calculation   of  similar   measures  for  other   entities.   Total
     capitalization  is not intended to  represent  the total funds from equity
     and debt received by the Trust.

The increase in net debt to total  capitalization  in 2006 is attributed to the
devaluation of the trust unit price following the Federal Government's proposed
Trust taxation announcement and an increase in debt. Prior to the announcement,
the trust unit price was $27.56 per unit and total capitalization  approximated
$6.3 billion.  The  devaluation of the unit price resulted in an approximate 20
per cent  decline in market  capitalization  resulting  in a higher net debt to
total capitalization ratio.

The Federal  Government's  proposed  Trust  taxation  announcement  also caused
increased market uncertainty pertaining to the future of the trust sector. This
market  uncertainty is diminishing over time, however it is our assessment that
the  Trust's  ability to raise  equity by issuing new trust units in the market
has been diminished.  The Government released guidelines regarding trust growth
that limits  expansion via  acquisitions  in 2007 to 40 per cent of the Trust's
market  capitalization as at October 31, 2006. We believe the 40 per cent limit
is in excess of what the Trust could  raise in the equity  markets on a prudent
basis.  Management's assessment is that the Trust's ability to raise new equity
would be dependant on financial market conditions at the time and the nature of
the use of proceeds.

The Trust has a syndicated  three year revolving  credit facility  allowing for
maximum borrowing of up to $572 million. The debt is secured by all the Trust's
oil and gas properties and has the following major covenants:

<TABLE>
<CAPTION>
==================================================================================================================================
COVENANT                                                                          POSITION AS OF DECEMBER 31, 2006
==================================================================================================================================
<S>                                                                 <C>
Long-term debt and letters of credit not to exceed three            Long-term debt and letters of credit of 0.9 times annualized
times annualized net income before non-cash items and               net income before non-cash items and interest expense
interest expense

----------------------------------------------------------------------------------------------------------------------------------
Long-term debt, letters of credit and subordinated debt not         Long-term debt, letters of credit and subordinated debt of 0.9
to exceed four times annualized net income before non-cash          times annualized net income before non-cash items
and interest items                                                  and interest expense expense

----------------------------------------------------------------------------------------------------------------------------------
Long-term debt and letters of credit not to exceed 50 per           Long-term debt and letters of credit of 26.8 per cent of the
cent of the sum of the book value of unitholders' equity,           sum of unitholders' equity, long-term debt, letters of credit,
long-term debt, letters of credit, and subordinated debt            and subordinated debt

==================================================================================================================================
</TABLE>

<PAGE>

As  indicated  by the  above  covenants,  the Trust  has  additional  potential
borrowing  capacity  above  the  $572  credit  facility,  however  the  Trust's
objective is to limit debt to under 2.0 times cash flow from  operations and 20
per cent of total capitalization.

In the event that the Trust  enters  into a material  acquisition  whereby  the
purchase price exceeds 10 per cent of the book value of the Trust's assets, the
ratios in the first two  covenants  above are  increased  to 3.5 and 5.5 times,
respectively.  The Trust had $4.7 million of letters of credit  outstanding  at
December 31, 2006 and no subordinated  debt. As at December 31, 2006, the Trust
was in compliance with all covenants.

In addition to the $572 million  credit  facility,  the Trust has issued senior
secured  notes which do not reduce the  available  borrowings  under the credit
facility.

Net debt  obligations  increased by $161 million in 2006 to $739.1 million as a
result  of  significant  capital  and  acquisition  activity  in the year  that
resulted in a working capital  deficit and the majority of acquisitions  having
been  funded  with  debt.  The  Trust  funded  72 per cent of its 2006  capital
development  program of $364.5 million with cash flow and the remaining  $101.2
million was funded with  proceeds from the DRIP and employee  rights plan.  The
Trust funded $125 million of the 2006  acquisitions with debt and the remaining
$6.8  million  was  funded  with  proceeds  from the DRIP and  Employee  Rights
program.

The Trust  intends to finance its $360 million  2007 capital  program with cash
flow  and the  proceeds  of the  distribution  reinvestment  program  with  any
remainder being financed with debt.


UNITHOLDERS' EQUITY

At December 31, 2006,  there were 207.2  million  units issued and issuable for
exchangeable  shares,  an increase of 5.2 million units from December 31, 2005.
The increase in number of units  outstanding is mainly  attributable to the 3.9
million  units issued  pursuant to the DRIP during 2006 at an average  price of
$24.67 per unit.

The Trust had 0.4 million  rights  outstanding as of December 31, 2006 under an
employee plan where further  rights  issuances were  discontinued  in 2004. The
rights have a five-year term and vest equally over three years from the date of
grant.  The majority of rights vested on May 6, 2006. The remaining  rights may
be  purchased  at an average  adjusted  exercise  price of $9.47 per unit as at
December  31,  2006.  All but 6,000 of the rights were fully vested at December
31, 2006 and the remainder will vest on March 22, 2007. The contractual life of
the rights varies by series but all will expire on or before March 22, 2009.

The  Whole  Unit  Plan  introduced  in 2004  is a cash  compensation  plan  for
employees,  officers and  directors of the Trust and does not involve any units
being issued from treasury. The Trust has made provisions whereby employees may
elect to have units  purchased  for them on the market  with the cash  received
upon vesting.

Unitholders  electing to reinvest  distributions or make optional cash payments
to  acquire  units  from  treasury  under the DRIP may do so at a five per cent
discount to the prevailing market price with no additional fees or commissions.
During 2006, the Trust raised  proceeds of $96.1 million and issued 3.9 million
trust units pursuant to the DRIP.


CASH DISTRIBUTIONS

ARC  declared  cash   distributions   of  $484.2   million  ($2.40  per  unit),
representing  64 per cent of 2006 cash flow from  operations  compared  to cash
distributions  of $376.6 million ($1.99 per unit),  representing 59 per cent of
cash flow from  operations in 2005. The remaining 36 per cent of 2006 cash flow
($276.4  million)  was  used  to  fund  72  per  cent  of  ARC's  2006  capital
expenditures and make  contributions,  including  interest,  to the reclamation
fund ($13.2 million).

Monthly cash distributions for 2006 were $0.20 per unit. Revisions,  if any, to
the monthly  distribution  are normally  announced on a quarterly  basis in the
context of prevailing and anticipated commodity prices at that time.

<PAGE>

The  following  items  may be  deducted  from  cash  flow  to  arrive  at  cash
distributions to unitholders:

o    An annual contribution to the reclamation funds and interest earned on the
     fund  balances.  The  reclamation  funds are  segregated  bank accounts or
     subsidiary  trusts and the balances will be drawn on in future  periods as
     the Trust incurs  abandonment and  reclamation  costs over the life of its
     properties.  The  contribution  level  is  reviewed  annually  based  on a
     detailed assessment of the Trust's total future abandonment obligation, an
     estimated  return  based on current  interest  rates and a future  funding
     period  approximating  50 years.  The  funding  amount is  approved by the
     Health,  Safety  and  Environment  committee.  As future  abandonment  and
     reclamation  obligations  will be settled with  reclamation  fund balances
     over  the life of the  properties,  the  Trust  does  not  anticipate  any
     separate  deductions from cash flow for abandonment and reclamation costs.
     The annual  contribution was $12.1 million in 2006 or two per cent of cash
     flow and will vary in future periods  depending on acquisition and capital
     development activity and abandonment cost estimates to reclaim the Trust's
     oil and natural gas properties.  The most significant annual contributions
     to the reclamation funds are expected to occur in years 2007 through 2015.
     The 2007 contribution is currently estimated to be $12 million.

o    The portion of capital  expenditures  that are funded with cash flow.  The
     Trust's  distribution policy guideline is to withhold at least 20 per cent
     of cash flow to fund a portion of capital expenditures. In 2006, the Trust
     withheld  34 per cent of 2006 cash flow to fund 72 per cent of the capital
     program  excluding  acquisitions.  The  objective  of the Trust's  capital
     expenditure program is to replace natural production declines resulting in
     stable production.  This level of capital expenditures may not replace the
     Trust's  reserves  produced  out  during  the  period,  but  rather  bring
     non-producing reserves on stream.

o    Debt principal  repayments to the extent that required principal repayment
     cannot be  refinanced  by other means.  The Trust's  current debt level is
     well  within  the  covenants   specified  in  the  debt   agreements  and,
     accordingly,  there are no current  mandatory  requirements for repayment.
     Refer to the "Capital  Structure and Liquidity" section of this MD&A for a
     detailed review of the debt covenants.

o    Income  taxes  that are not  passed  on to  unitholders.  The  Trust has a
     liability for future income taxes due to the excess of book value over the
     tax basis of the assets of the Trust and its corporate  subsidiaries.  The
     Trust  currently  minimizes or  eliminates  cash income taxes in corporate
     subsidiaries by maximizing deductions, however in future periods there may
     be cash income taxes if deductions are not sufficient to eliminate taxable
     income and if proposed  changes in Trust taxation are enacted.  Taxability
     of the Trust is currently  passed on to unitholders in the form of taxable
     distributions  whereby  corporate income taxes are eliminated at the Trust
     level.  If the proposed Trust taxation  legislation is enacted,  the Trust
     anticipates  that the resulting tax  commencing in 2011 at the Trust level
     would   decrease  cash  flow  and  thus  reduce  cash   distributions   to
     unitholders.

o    Working capital  requirements as determined by the Trust.  Certain working
     capital amounts may be deducted from cash flow, however such amounts would
     be minimal and the Trust does not  anticipate  any such  deductions in the
     foreseeable future.

o    The Trust has certain obligations for future payments relative to employee
     long-term  incentive  compensation.  Presently,  the Trust  estimates that
     $18.2  million  to  $58.6  million  will  be  paid  out  pursuant  to such
     commitments in 2007 through 2009 subject to vesting  provisions and future
     performance of the Trust.  These amounts will reduce cash flow and in turn
     cash distributions in future periods.


<PAGE>

Cash flow and cash distributions in total and per unit were as follows:

<TABLE>
<CAPTION>
CASH FLOW AND DISTRIBUTIONS
                                                           ($ million)                        ($ per unit)
===========================================================================================================================
($ millions and $ per unit)                              2006       2005     % Change       2006       2005      % Change
===========================================================================================================================
<S>                                                    <C>        <C>        <C>          <C>        <C>          <C>
Cash flow from operations                               760.6      639.5       19           3.72       3.35         11
Reclamation fund contributions (1)                      (13.2)      (6.8)      94          (0.06)     (0.04)        50
Capital expenditures funded with cash flow             (263.2)    (256.1)       3          (1.28)     (1.34)        (4)
Other (2)                                                   -          -                    0.02       0.02          -
---------------------------------------------------------------------------------------------------------------------------
Cash distributions                                      484.2      376.6       29           2.40       1.99         21
===========================================================================================================================
</TABLE>
(1)  Includes  interest income earned on the reclamation  fund balances that is
     retained in the reclamation funds.
(2)  Other represents the difference due to cash distributions paid being based
     on actual  units at each  distribution  date  whereas  per unit cash flow,
     reclamation fund contributions and capital  expenditures  funded with cash
     flow are based on  weighted  average  trust  units in the year plus  units
     issuable for exchangeable shares at year-end.

The Trust  continually  assesses  distribution  levels,  in light of  commodity
prices and production  volumes,  to ensure that  distributions are in line with
the  long-term  strategy  and  objectives  of the  Trust  as per the  following
guidelines:

o    To maintain a level of  distributions  that,  in the opinion of Management
     and the Board of Directors,  are  sustainable  for a minimum period of six
     months.  The Trust's objective is to normalize the effect of volatility of
     commodity  prices rather than to pass on that volatility to unitholders in
     the form of fluctuating monthly distributions.

o    To ensure that the Trust's  payout ratio does not exceed 80 per cent on an
     annual  basis.  The Trust  believes  that a portion of cash flow should be
     reinvested in capital development  activities in order to offset, in part,
     the natural production  declines of the Trust's assets over the long-term.
     The use of cash flow to fund capital  development  activities  reduces the
     requirements  of the  Trust  to use  debt  and  equity  to  finance  these
     expenditures.  In 2006 the Trust funded 72 per cent of capital development
     activities  with 34 per cent of cash flow.  The actual amount of cash flow
     withheld to fund the Trust's capital  expenditure  program is dependent on
     the commodity  price  environment and is at the discretion of the Board of
     Directors.

In order to set  distributions  to meet the above noted  objectives,  the Trust
maintains an annual cash flow forecast that incorporates  actual results of the
Trust and market conditions.  An annual distribution is determined based on the
Trust's  objectives of a maximum  annual payout ratio of 80 per cent, a minimum
of 20 per cent of annual cash flow to fund capital expenditures,  and a minimum
annual  contribution to the reclamation funds. As market conditions change, the
forecast is updated to assess whether there should be a change in  distribution
levels.  A change to  distributions  is proposed  only if there is a reasonable
probability  that the  revised  distribution  may be  maintained  for a minimum
six-month  period.  If  distribution  levels remain the same, the difference in
cash flow  between  estimated  and actual  results is reflected in the level of
cash funded capital expenditures.

The  actual  amount  of future  monthly  cash  distributions  are  proposed  by
management  and are  subject to the  approval  and  discretion  of the Board of
Directors.  The Board reviews future cash  distributions  in  conjunction  with
their review of quarterly financial and operating results.

Monthly cash distributions for the first quarter of 2007 have been set at $0.20
per unit  subject to monthly  review  based on  commodity  price  fluctuations.
Revisions,  if any, to the monthly  distribution  are  normally  announced on a
quarterly basis in the context of prevailing and anticipated  commodity  prices
at that time.

<PAGE>

Historical Cash Distributions by Calendar Year
The following table presents cash distributions paid and payable for each
calendar period.

<TABLE>
<CAPTION>
=====================================================================================================
CALENDAR YEAR                               DISTRIBUTIONS    TAXABLE PORTION      RETURN OF CAPITAL
=====================================================================================================
<C>                                         <C>              <C>  <C>             <C>
2007 YTD (2)                                     0.20             0.20 (2)             0.00 (2)
2006 (1)                                         2.60             2.55 (3)             0.05 (3)
2005                                             1.94             1.90                 0.04
2004                                             1.80             1.69                 0.11
2003                                             1.78             1.51                 0.27
2002                                             1.58             1.07                 0.51
2001                                             2.41             1.64                 0.77
2000                                             1.86             0.84                 1.02
1999                                             1.25             0.26                 0.99
1998                                             1.20             0.12                 1.08
1997                                             1.40             0.31                 1.09
1996                                             0.81                -                 0.81
-----------------------------------------------------------------------------------------------------
Cumulative                                    $ 18.83          $ 12.09              $  6.74
=====================================================================================================
</TABLE>
(1)  Based on cash distributions paid and payable in 2006.
(2)  Based on cash  distributions  declared at January  31, 2007 and  estimated
     taxable portion of 2007 distributions of 98 per cent.
(3)  Based on taxable portion of 2006 distributions of 98 per cent.

2006 Monthly Cash Distributions
Actual cash distributions paid and payable in 2006 along with relevant payment
dates were as follows:

<TABLE>
<CAPTION>
=========================================================================================================
EX-DISTRIBUTION DATE          RECORD DATE               DISTRIBUTION PAYMENT DATE    TOTAL DISTRIBUTION
=========================================================================================================
<S>                           <C>                       <C>                          <C>
December 28, 2005             December 31, 2005         January 16, 2006                   0.20
January 27, 2006              January 31, 2006          February 15, 2006                  0.20
February 24, 2006             February 28, 2006         March 15, 2006                     0.20
March 29, 2006                March 31, 2006            April 17, 2006                     0.20
April 26, 2006                April 30, 2006            May 15, 2006                       0.20
May 29, 2006                  May 31, 2006              June 15, 2006                      0.20
June 28, 2006                 June 30, 2006             July 17, 2006                      0.20
July 27, 2006                 July 31, 2006             August 15, 2006                    0.20
August 29, 2006               August 31, 2006           September 15, 2006                 0.20
September 27, 2006            September 30, 2006        October 16, 2006                   0.20
October 27, 2006              October 31, 2006          November 15, 2006                  0.20
November 28, 2006             November 30, 2006         December 15, 2006                  0.20
December 27, 2006             December 31, 2006         January 15, 2007                   0.20
-----------------------------------------------------------------------------------------------------
Total 2006                                                                                 2.60 (1)
=========================================================================================================
</TABLE>
(1)  At the Annual and Special Meeting of Unitholders  held on Monday,  May 15,
     2006, the Unitholders approved amendments to the Trust Indenture including
     a modification to the  distribution  language to ensure that all income of
     the Trust as of December 31 in each year is payable to  Unitholders.  As a
     result of this  amendment,  beginning in 2006 the  distributions  declared
     payable to  Unitholders  on the December 31st record date will be included
     in  the  Unitholder's   income  in  that  calendar  year.  For  2006,  the
     Unitholders  will include  distributions  with respect to record dates for
     the period December 31, 2005 to December 31, 2006, i.e. 13 distributions.

Please refer to the Trust's  website at  www.arcenergytrust.com  for details on
distributions dates for 2007.

TAXATION OF CASH DISTRIBUTIONS

Cash  distributions  comprise a return of capital  portion (tax deferred) and a
return on capital portion  (taxable).  The return of capital  component reduces
the cost basis of the units  held.  For 2006,  cash  distributions  paid in the
calendar year will be 98 per cent return on capital  (taxable) and two per cent
return of capital (tax  deferred).For a more detailed  breakdown,  please visit
our website at www.arcenergytrust.com.

The proposed Trust taxation  announced by the Federal Government on October 31,
2006 and  subsequent  draft  legislation  would  result in income  taxes  being
imposed  at the Trust  level on  distributions  paid to  unitholders  effective
January  1,  2011.  The Trust is  currently  assessing  the  proposals  and the
potential implications to the Trust in future periods.

<PAGE>

DEFICIT

During the  second  quarter,  presentation  changes  were made to  combine  the
previously  reported  accumulated  earnings and accumulated  cash  distribution
figures on the  balance  sheet  into a single  deficit  balance.  The Trust has
historically paid cash distributions in excess of accumulated  earnings as cash
distributions  are based on cash flow  generated in the current  period,  while
accumulated  earnings are based on cash flow  generated  in the current  period
less a depletion and depreciation  expense  recorded on the original  property,
plant, and equipment  investment.  Numbers  presented for comparative  purposes
have been restated to reflect this change in presentation.

CONTRACTUAL OBLIGATIONS AND COMMITMENTS

The  Trust has  contractual  obligations  in the  normal  course of  operations
including purchase of assets and services, operating agreements, transportation
commitments,   sales  commitments,   royalty  obligations,   and  lease  rental
obligations.  These  obligations  are of a recurring and consistent  nature and
impact  cash  flow  in an  ongoing  manner.  The  Trust  also  has  contractual
obligations and  commitments  that are of a less routine nature as disclosed in
the following table.

<TABLE>
<CAPTION>
COMMITMENTS
                                                            PAYMENTS DUE BY PERIOD
===================================================================================================================
($ millions)                                  2007         2008 - 2009      2010-1011      Thereafter       Total
===================================================================================================================
<S>                                         <C>            <C>             <C>             <C>           <C>
Debt repayments                                8.0            451.2           53.1             174.8        687.1
Interest payments (1)                         11.3             21.5           18.1              20.8         71.7
Reclamation fund contributions (2)             6.0             11.1            9.5              76.2        102.8
Purchase commitments                          12.6              8.4            3.4               6.8         31.2
Operating leases                               5.3              9.9            5.0                 -         20.2
Derivative contract premiums (3)              12.4              3.3              -                 -         15.7
Retention bonuses                              1.0                -              -                 -          1.0
-------------------------------------------------------------------------------------------------------------------
Total Contractual Obligations                 56.6            505.4           89.1             278.6        929.7
===================================================================================================================
</TABLE>
(1)  Fixed interest payments on the Senior Secured Notes.
(2)  Contribution  commitments to a restricted reclamation fund associated with
     the Redwater property acquired in 2005.
(3)  Fixed  premiums  to  be  paid  in  future  periods  on  certain  commodity
     derivative contracts.

The  above  noted  derivative   contract  premiums  are  part  of  the  Trust's
commitments  related to its risk management  program.  In addition to the above
premiums,  the Trust has commitments related to its risk management program. As
the premiums are part of the  underlying  derivative  contract,  they have been
recorded at fair market value at December 31, 2006 on the balance sheet as part
of commodity and foreign currency contracts.

The Trust enters into  commitments  for capital  expenditures in advance of the
expenditures  being made.  At a given point in time,  it is estimated  that the
Trust has committed to capital  expenditures equal to approximately one quarter
of its capital budget by means of giving the necessary  authorizations to incur
the  capital in a future  period.  The  Trust's  2007  capital  budget has been
approved by the Board at $360 million.  This  commitment has not been disclosed
in the  commitment  table as it is of a  routine  nature  and is part of normal
course of operations for active oil and gas companies and trusts.

The Trust is involved in litigation  and claims arising in the normal course of
operations.  Management is of the opinion that pending litigation will not have
a material  adverse  impact on the  Trust's  financial  position  or results of
operations and therefore the following  table does not include any  commitments
for outstanding litigation and claims.

The Trust has  certain  sales  contracts  with  aggregators  whereby  the price
received  by the Trust is  dependent  upon the  contracts  entered  into by the
aggregator.  This commitment has not been disclosed in the commitment  table as
it is of a routine nature and is part of normal course of operations.


OFF BALANCE SHEET ARRANGEMENTS

The Trust has certain lease  agreements which aggregate to less that $1 million
and were entered into in the normal course of operations.  All leases have been
treated  as  operating  leases  whereby  the lease  payments  are  included  in
operating  expenses or G&A expenses  depending  on the nature of the lease.  No
asset or liability value has been assigned to these leases in the balance sheet
as of December 31, 2006.

The Trust's long-term  electricity hedge and interest rate hedges have not been
recorded  as an asset or  liability  on the  balance  sheet as they  qualify as
effective accounting hedges.

The Trust entered into agreements to pay premiums pursuant to certain crude oil
derivative  put  contracts.  Premiums  of  $15.7  million  will be paid in 2007
through  2009 for the put  contracts  in place at  December  31,  2006.  As the
premiums  are  part of the  underlying  derivative  contract,  they  have  been
recorded at fair market value at December 31, 2006 on the balance sheet.

<PAGE>

CRITICAL ACCOUNTING ESTIMATES

The Trust has  continuously  evolved and documented its management and internal
reporting  systems to provide  assurance  that  accurate,  timely  internal and
external information is gathered and disseminated.

The Trust's  financial  and operating  results  incorporate  certain  estimates
including:

o    estimated  revenues,  royalties and operating  costs on production as at a
     specific  reporting date but for which actual  revenues and costs have not
     yet been received;

o    estimated capital expenditures on projects that are in progress;

o    estimated  depletion,   depreciation  and  accretion  that  are  based  on
     estimates of oil and gas reserves that the Trust expects to recover in the
     future;

o    estimated  fair  values  of  derivative  contracts  that  are  subject  to
     fluctuation  depending  upon the underlying  commodity  prices and foreign
     exchange rates;

o    estimated value of asset  retirement  obligations  that are dependent upon
     estimates of future costs and timing of expenditures; and
o    estimated future  recoverable  value of property,  plant and equipment and
     goodwill.

The Trust has hired individuals and consultants who have the skills required to
make such estimates and ensures that  individuals or departments  with the most
knowledge of the activity are  responsible  for the  estimates.  Further,  past
estimates are reviewed and compared to actual  results,  and actual results are
compared  to  budgets  in order  to make  more  informed  decisions  on  future
estimates.

The ARC leadership  team's mandate includes ongoing  development of procedures,
standards  and systems to allow ARC staff to make the best  decisions  possible
and ensuring those decisions are in compliance with the Trust's  environmental,
health and safety policies.


INTERNAL CONTROLS UPDATE

On July 31, 2002, the United States  Congress  enacted the  Sarbanes-Oxley  Act
("SOX").  SOX  applies to all  companies  registered  with the  Securities  and
Exchange  Commission  ("SEC").  Although  ARC is  not  listed  on a U.S.  stock
exchange,  the Trust is registered  with the SEC as a result of having acquired
Startech  Energy Inc. in 2001 and therefore was required to comply with section
404 of the SOX legislation as at December 31, 2006 and each year thereafter.

There  are  various  components  to  the  SOX  legislation,  however  the  most
comprehensive  is Section 404  "Internal  Controls Over  Financial  Reporting".
Section 404 requires that management undertake the following:

o    identify and document internal controls that impact financial reporting;

o    assess the effectiveness of those internal controls;

o    remediate  any  deficiencies  in internal  controls  and/or  implement any
     required controls that are not already in place;

o    test the internal controls to ensure that they are operating  effectively;
     and

o    issue a report,  to be signed by the Chief Operating Officer and the Chief
     Financial  Officer,  on management's  assessment of the  effectiveness  of
     internal controls and communicate any material weaknesses.

Internal  control over  financial  reporting  is a process  designed to provide
reasonable  assurance  that  all  assets  are  safeguarded,   transactions  are
appropriately  authorized  and  to  facilitate  the  preparation  of  relevant,
reliable and timely information. Because of its inherent limitations,  internal
control  over  financial  reporting  may not  prevent or detect  misstatements.
Management has assessed the  effectiveness  of the company's  internal  control
over financial reporting based on the criteria in Internal Control - Integrated
Framework  issued by the Committee of Sponsoring  Organizations of the Treadway
Commission  (COSO) and  concluded  that the  company's  internal  control  over
financial  reporting  was  effective  as of  December  31,  2006.  Management's
assessment  of  the  effectiveness  of  the  company's  internal  control  over
financial  reporting  as of December  31,  2006 has been  audited by Deloitte &
Touche LLP, as reflected in their report for 2006.

As of  December  31,  2006,  an  internal  evaluation  was  carried  out of the
effectiveness of the Trust's  disclosure  controls and procedures as defined in
Rule 13a-15 under the US  Securities  Exchange  Act of 1934,  also known as SOX
302. Based on that  evaluation,  the President and Chief Executive  Officer and
Chief Financial Officer  concluded that the disclosure  controls and procedures
are  effective to ensure that the  information  required to be disclosed in the
reports  that the Trust files or submits  under the  Exchange  Act is recorded,
processed,  summarized and reported,  within the time periods  specified in the
rules and forms of the SEC. Disclosure controls and procedures include, without
limitation,  controls and  procedures  designed to ensure that the  information
required to be  disclosed  by the Trust in the reports that it files or submits
under  the  Exchange  Act  is  accumulated  and  communicated  to  the  Trust's
management,   including  the  senior  executive  and  financial  officers,   as
appropriate to allow timely decisions regarding the required disclosure.

<PAGE>

In addition to SOX,  ARC is  required  to comply with  Multilateral  Instrument
52-109  "Certification  of Disclosure in Issuers' Annual and Interim  Filings",
otherwise  referred to as Canadian SOX  ("C-Sox").  The  Canadian  requirements
closely parallel the SEC's certification rules, however,  currently there is no
requirement to have the external auditor opine on the Trust's internal controls
or management's  assessment thereof.  ARC has complied with this legislation by
filing  bare  interim  certificates  and a  full  annual  certificate  with  no
modifications  in  conjunction  with the  December  31, 2006 year end. The 2006
certificate  requires that the Trust disclose in the annual MD&A any changes in
the Trust's internal control over financial  reporting that occurred during the
period that has  materially  affected,  or is  reasonably  likely to materially
affect  the  Trust's  internal  control  over  financial  reporting.  The Trust
confirms that no such changes were made to the internal controls over financial
reporting during 2006.

FINANCIAL REPORTING UPDATE

During 2006, the Trust commenced a review of the new CICA Handbook section 3855
"Financial   Instruments  -   Recognition   and   Measurement",   section  1530
"Comprehensive Income" and section 3865 "Hedges" that deal with the recognition
and  measurement  of  financial  instruments  at fair  value and  comprehensive
income.  The new standards are intended to harmonize  Canadian  standards  with
United States and  international  accounting  standards.  The new standards are
effective for annual and interim  periods in fiscal years beginning on or after
October  1, 2006.  These new  standards  will  impact the Trust in 2007 and are
currently being reviewed to assess their impact.

OBJECTIVES AND 2007 OUTLOOK

Sustainability  It is the Trust's objective to provide superior and sustainable
long-term returns to unitholders by focusing on the key strategic objectives of
the business plan. The Trust  acquires,  develops and optimizes oil and natural
gas  properties in  predominantly  mature areas to generate a cash flow stream.
Due to natural  production  declines,  the Trust must  continually  develop its
reserves  and/or  acquire  new  reserves  in an  effort to  maintain  reserves,
production  and cash flow  levels on which  distributions  are paid.  The trust
facilitates  this by  withholding  a portion  of cash flow to fund a portion of
ongoing capital  development  activities and maintaining  moderate debt levels;
this is evidenced by the Trust's low payout ratio.  Oil and gas royalty  trusts
hold  assets that are  depleting  and  unitholders  should  expect  production,
revenue,  cash flow and distributions to decline over the long-term if reserves
cannot  be  economically  replaced.  The  Trust has an  inventory  of  internal
development  prospects  that will enable the Trust to maintain  production  and
reserves for a minimum period of two years. The Trust  anticipates  employing a
conservative  payout policy to provide for cash funding of a portion of ongoing
capital  development  programs and  maintaining  low debt levels to  facilitate
further growth.  The Trust measures its  sustainability and success in terms of
per unit cash distributions, production, reserves, and cash flow in addition to
the ability to maintain low debt levels and the annual replacement of reserves.

Following is a summary of the historical  debt-adjusted production and reserves
per unit and reserve  life index on which the Trust  assesses  performance  and
sustainability:

<TABLE>
<CAPTION>
=====================================================================================================================
Per Trust Unit Ratios                    2006          2005         2004         2003         2002      5 Year Total
=====================================================================================================================
<S>                                      <C>          <C>          <C>          <C>          <C>        <C>
Production per unit: (1)
---------------------------------------------------------------------------------------------------------------------
Unadjusted                               0.31          0.29         0.31         0.35         0.35           -
Debt-adjusted (3)                        0.27          0.26         0.28         0.31         0.29           -
Normalized (4)                           0.31          0.31         0.33         0.38         0.33           -
---------------------------------------------------------------------------------------------------------------------
Reserves per unit: (2)
---------------------------------------------------------------------------------------------------------------------
Unadjusted                               1.38          1.42         1.29         1.37         1.47           -
Debt-adjusted (3)                        1.19          1.28         1.20         1.25         1.19           -
Normalized (4)                           1.38          1.49         1.39         1.44         1.38           -
---------------------------------------------------------------------------------------------------------------------
Reserve life index (5)                   12.4          12.9         12.2         12.4         11.8           -
Cash flow per unit                       3.72          3.35         2.41         2.56         1.87       13.91
Cash distributions per unit              2.40          1.99         1.80         1.80         1.56        9.55
Payout ratio per cent (6)                  64            59           74           71           82          70
Per cent of cash flow retained             36            41           26           29           18          30
=====================================================================================================================
</TABLE>
(1)  Represents daily average  production per thousand units.  Calculated based
     on annual daily average production divided by weighted average trust units
     outstanding including trust units issuable for exchangeable shares.
(2)  Calculated  based on proved plus probable  reserves  divided by period end
     trust units  outstanding  including trust units issuable for  exchangeable
     shares.
(3)  Debt-adjusted  indicates that all years as presented have been adjusted to
     reflect a nil net debt to  capitalization.  It is assumed that  additional
     trust  units were issued at a period end price for the  reserves  per unit
     calculation  and at an annual  average price for the  production  per unit
     calculation  in order to reduce the net debt balance to zero in each year.
     The debt-adjusted  amounts are presented to enable comparability of annual
     per unit values.
(4)  Normalized  indicates  that all years as presented  have been  adjusted to
     reflect a net debt to  capitalization  of 14 per cent as per  December 31,
     2006.  It  is  assumed  that  additional   trust  units  were  issued  (or
     repurchased)  at a period end price for the reserves per unit  calculation
     and at an annual average price for the production per unit  calculation in
     order  to  reduce   the  net  debt   balance  to  14  per  cent  of  total
     capitalization  each year. The normalized  amounts are presented to enable
     comparability of annual per unit values.
(5)  Calculated  based on proved plus probable  reserves divided by annual 2007
     production estimate of 63,000 boe per day for 2006 RLI.
(6)  Calculated as cash distributions divided by cash flow from operations.

<PAGE>

During the 2002 to 2006 time period the trust's normalized  production per unit
has decreased  only slightly from 0.33 to 0.31 boe of daily average  production
per  thousand  trust  units and  normalized  reserves  per unit  have  remained
constant  during this time at 1.38 boe of proved  plus  probable  reserves  per
trust unit.  The  maintenance of production and reserves per unit occurred even
with the payout of $1.7 billion of cash distributions ($9.55 per trust unit and
70 per cent of cash  flow)  during  the 2002  through  2006 time  period.  This
indicates  that the Trust has  continually  grown  production  levels to offset
natural  production  declines and  developed  and grown its reserve  base.  The
normalized  production per unit is a key measure as it indicates the ability to
generate cash flow from core operations which in turn impacts the level of cash
that may be distributed to unitholders. The Trust expects to replace production
in 2007 from internal development opportunities.

To compare the Trust's  results with oil and gas  companies  that retain all of
their cash flow to grow production and reserves,  the Trust looks at normalized
and distribution-adjusted production and reserves per unit which calculates the
total reserves and production per initial  investment  with the assumption that
distributions are reinvested through the DRIP plan. Consequently,  the reserves
and  production  per initial  investment  increase over time as the  investor's
number of trust units  increase  with  distribution  reinvestment.  The Trust's
normalized daily average  production per initial  investment has increased from
0.33 boe per  thousand  trust units in 2002 to 0.56 in 2006,  while  normalized
reserves per initial investment have increased from 1.53 boe at January 1, 2002
to 2.50 boe at December 31, 2006. The increase is attributed to the DRIP factor
whereby  one trust unit  purchased  on January 1, 2002 would have grown to 1.81
trust  units  on  December  31,  2006.  A  unitholder  can  replicate  this  by
participating  in the DRIP so that the number of units they own increases  over
time.

The Trust's  reserve  life index  ("RLI")  increased to 12.4 years in 2006 from
11.8 years in 2002.  The RLI is a measure of the remaining  average life of the
reserves based on a current production estimate for 2007 of 63,000 boe per day.
The  Trust's  high RLI is  indicative  of the high  quality  of assets and long
reserve  life of the  properties.  The  acquisition  of the  Redwater  and NPCU
properties  in 2005  resulted in an increase in the RLI due to the long reserve
life  of the  properties.  A  high  RLI is key  for a  royalty  trust  as it is
indicates the potential  sustainability of production levels and cash flow over
a longer period of time.

The  Trust's  distribution  policy  centres  around  the  goal of  providing  a
consistent and sustainable level of distributions to unitholders and to provide
for future growth. The low payout ratio is indicative of the Trust's commitment
to fund  ongoing  development  activities  with cash  flow to enable  long-term
sustainability.  A high payout ratio indicates that ongoing capital development
activities must be either debt or equity financed. The Trust's payout ratio has
declined  over  time  as  the  Trust  has  addressed  the  issue  of  long-term
sustainability while setting distribution levels.

An additional measure of sustainability is the comparison of net income to cash
distributions.  Net income  incorporates all costs including  depletion expense
and other non-cash expenses whereas cash flow from operations measures the cash
generated  in a  given  period  before  the  cost of the  associated  reserves.
Therefore,  net income may be more  representative  of the profitability of the
entity and thus a relevant measure against which to measure cash  distributions
to illustrate  sustainability.  As net income is sensitive to  fluctuations  in
commodity prices,  it is expected that there will be deviations  between annual
net income and cash  distributions.  The following table illustrates the annual
excess or  shortfall  of cash  distributions  to net  income  as a  measure  of
long-term sustainability.

NET INCOME AND CASH DISTRIBUTIONS

<TABLE>
<CAPTION>
==============================================================================================================================
($ millions except per cent)                     2006          2005         2004         2003         2002      5 Year Total
==============================================================================================================================
<S>                                              <C>          <C>          <C>          <C>          <C>        <C>
Net income                                      460.1         356.9        241.7        284.6         70.0         1,413.3
Cash distributions                              484.2         376.6        330.0        279.3        183.6         1,653.7
------------------------------------------------------------------------------------------------------------------------------
Excess (shortfall)                              (24.1)        (19.7)       (88.3)         5.3       (113.6)         (240.4)
Excess (shortfall) as per cent of net income       (5%)          (6%)        (37%)          2%         (62%)         (17%)
Payout of cash flow per cent                       64%           59%          74%          71%          82%           70%
==============================================================================================================================
</TABLE>

During 2002 through 2004, there was significant  volatility in commodity prices
and it was  management's  decision to maintain  distributions  at a  consistent
level during that time as it was perceived that the decline in commodity prices
was  temporary.  Management's  decision  to lower  payout  ratios  over time is
illustrated in the table as cash  distributions  more closely  approximate  net
income in 2005 and 2006.

Returns to Unitholders  and Proposed  Federal  Legislation to Tax Income Trusts
The Trust has provided  unitholders with the following one, three and five year
returns, including reinvestment of distributions:

TOTAL RETURNS
===============================================================================
($ per unit except for per cent)        One Year     Three Year     Five Year
===============================================================================
Distributions per unit                 $   2.40        $   6.19       $  9.55
Capital appreciation per unit          $  (4.19)       $   7.56       $  10.20
Total return per unit                  $  (1.79)       $  13.75       $  19.75
Annualized total return per unit       %   (8.0)       %   26.7       %   26.5
===============================================================================

<PAGE>

To the end of 2006, the Trust has provided  cumulative  cash  distributions  of
$18.63 per unit and capital  appreciation of $12.30 per unit for a total return
of $30.93 per unit (23.8 per cent annualized  total return) for unitholders who
invested in the Trust at inception in 1996.  The Trust has announced  2007 cash
distributions of $0.20 per unit per month through March 2007.

During  2006,  the  announcement   and  subsequent   introduction  of  proposed
legislation  regarding taxation of Trusts resulted in a significant  decline in
trust unit  prices  throughout  the  industry.  Consequently,  many trusts have
reported  a negative  total  return to  unitholders  in 2006 as a result of the
decline in trust unit prices  immediately  following  the  announcement.  ARC's
return to  unitholders  was negative eight per cent in 2006 as a result of a 20
per cent  decline in the trust  unit price  following  the  Federal  Government
announcement  on October 31, 2006.  The Trust had reached a historic  high unit
price of $30.74 in August 2006.  Annual  distributions  to unitholders of $2.40
per trust unit are our highest to date.

Despite the  devaluation  of the trust unit price  following the proposed Trust
taxation announcement,  the Trust's business remains unchanged and the Trust is
still  a  prospering  and  sustainable  entity  with  no  change  to  the  core
operations.  Subsequent  to the  announcement,  the  Trust  has  been  actively
researching  alternatives regarding the structure and business strategy leading
up to the  implementation  of the  proposed  tax in  2011.  Under  the  current
proposed  legislation,  the most viable  option  appears to be  conversion to a
corporate entity no earlier than January 1, 2011 due to the punitive  financial
impact that the taxation would have on the trust structure. However, given that
the  legislation has not been  officially  enacted,  the Trust has not made any
conclusive  decisions  with respect to the strategy over the next four years as
we feel it is prudent to await the final  legislation  and fully  research  all
alternatives before making a final decision.  The Trust is working closely with
legal and business  advisors as to the potential future structure and direction
of the Trust in an effort to maximize the value to unitholders, and to choose a
direction which is in the best interest of its unitholders.

ARC plans to proceed with its full $360 million capital  expenditure budget for
2007 which consists of a robust drilling and development program on its diverse
asset base. The 2007 capital budget is being deployed on well tie-ins and other
facility  related costs, a balanced  drilling  program of low and moderate risk
wells and the acquisition of undeveloped  land. The Trust continues to focus on
major  properties  with  significant  upside,  with the  objective  to  replace
production  declines  through  internal  development  opportunities.  The  2007
capital  expenditure  budget anticipates the drilling of 225 net operated wells
and the  addition  of 11,000  boe per day of new  production  from the  capital
development  program to  replace  declines  at  existing  properties.  The 2007
capital  budget also allows for a portion of spending to further  research  and
pursue Enhanced Recovery Initiatives such as CO2 injection and NGC development.
Despite the Trust's  active  fourth  quarter,  there was a general slow down in
activity  levels for the industry late in 2006. The Trust expects that with the
lower  activity  levels and decreased  demand for industry  services that costs
will moderate  slightly in 2007.  Current low debt levels and a strong  working
capital position  provide the Trust with the financial  flexibility to fund the
2007 capital expenditure program.

The  Trust  continually  looks  to  execute  minor  property  acquisitions  and
dispositions  in order to enhance and streamline  the Trust's  portfolio of oil
and natural gas assets. The Trust continually reviews potential acquisitions of
both  conventional  oil and natural  gas  reserves  and in the  broader  energy
industry. The Federal Government issued guidance with respect to limitations on
future  growth of the Trust in  conjunction  with the proposed  Trust  taxation
announcement. The Trust does not anticipate that the guidelines will impair the
Trust's ability to annually  replace or grow reserves in the next four years as
the guidelines  allow sufficient  growth targets.  Key attributes of the future
growth constraints are as follows:

o    Trusts may grow in size by 100 per cent  cumulatively  for the period 2007
     through  2010 as measured by the value of equity  based on the October 31,
     2006 market capitalization.  The cumulative limit starts at 40 per cent in
     2007 and increases by 20 per cent per year in 2008 through 2010.

o    Merger of two Trusts will not be impacted by the growth limitations.

o    The growth limits are not impacted by non-convertible debt-financed growth
     but rather focus solely on the issuance of equity to facilitate growth.

The  Trust  will  continue  to  assess  accretive  acquisition   opportunities.
Acquisitions are evaluated internally and acquisitions in excess of $25 million
are subject to Board approval.

ACCOMPLISHMENT OF 2006 OBJECTIVES

The key future  objectives of the Trust's  business plan, as identified  below,
are reviewed  annually by the Board. The Trust was successful in meeting all of
its objectives in 2006 as individually addressed below. They continue to be key
objectives for 2007.

o    Annual  reserves  replacement - The Trust's proved plus probable  reserves
     were  effectively  maintained as December 31, 2006 reserves of 286.1 mmboe
     were  within one per cent of the 287 mmboe  recorded  as at  December  31,
     2005.  The reserves were  maintained  through a combination  of the $364.5
     million  2006  capital  development  program and  corporate  and  property
     acquisitions (net of dispositions) of $131.8 million.

o    Ensuring  acquisitions are strategic and enhance  unitholder returns - The
     Trust added producing properties in Manitoba to its asset base in 2006 and
     also  increased  its land  ownership  in certain  core areas in 2006 in an
     effort to increase its inventory of future development  opportunities.  In
     addition,   the  Redwater   property   acquired  in  2005   provided  many
     opportunities to ARC due to the optimization  potential of this long-life,
     light oil property. Since acquisition,  ARC has reactivated 95 gross wells
     (62  net  wells)  at  Redwater  and  NPCU  and  increased   production  by
     approximately 580 boe per day net. ARC believes that long-life,  light oil
     properties will provide future  opportunities to enhance  unitholder value
     through the application of tertiary recovery methods.

<PAGE>

o    Controlling  costs - Due to the  diligence  of field and office  operating
     staff,  the Trust's  base  operating  costs per boe,  before the impact of
     higher cost  acquisitions,  increased by approximately  five per cent over
     2005 costs.  Cash G&A costs in 2006 increased 18 per cent to $1.58 per boe
     from  $1.34 per boe in 2005 as a result  of both  increased  staff  counts
     following  acquisitions  and  increased  compensation  costs  due  to  the
     extremely  competitive  marketplace for experienced staff with oil and gas
     expertise.  The Trust  believes  the $1.58 per boe cash G&A costs  will be
     better than  average for  mid-sized  oil and gas  producers  in 2006.  The
     Trust's  three  year  average  FD&A  costs  of  $15.59  per boe  prior  to
     incorporating future development costs ("FDC") and $18.99 per boe with FDC
     are expected to  approximate  the industry  average.  The increase in FD&A
     costs in 2006 is considered an anomaly partly due to the large  investment
     in  strategic  undeveloped  land  with no  associated  reserves.  The land
     acquisitions provide future development  opportunities and are expected to
     yield reserves in future periods as development occurs.

o    Conservative  utilization of debt - The Trust's net debt levels were under
     14 per  cent of  total  capitalization  and  debt to 2006  cash  flow  was
     slightly  less than 1.0 times for the year ended  2006.  With the  Federal
     Government's  proposed  Trust  taxation  announcement,  the Trust's market
     capitalization  fell by  approximately 20 per cent to $4.5 billion whereby
     the net debt to total capitalization  increased  accordingly.  The Trust's
     debt  levels  are still  considered  to be one of the  lowest in the Trust
     sector.

o    Continuously developing the expertise of our staff and seeking to hire and
     retain the best in the  industry - The Trust runs an active  training  and
     development program for its employees and encourages personal development.
     The Trust  continues  to assess  compensation  levels in the  industry  to
     ensure that the Trust's  compensation  is competitive so as to attract and
     retain the best employees.  The Trust's long-term incentive plan's payouts
     are directly tied to the Trust's  performance  providing alignment between
     employees and investors.

o    Building  relationships and conducting business in a way that is viewed as
     fair and equitable - ARC  employees,  leadership  team and directors  work
     hard to  build  the ARC  "franchise  value"  through  honest,  transparent
     dealings with our business partners. "Treating all people with respect" is
     a key message  inside and outside the  organization.  This basic  business
     fundamental  allows us to build enduring  relationships with joint venture
     partners,  land  owners,   investors,   banks  and  lending  institutions,
     governments and the investment community.

o    Promoting  the  use of  proven  and  effective  technologies  - The  Trust
     continues  to  research  new  technologies  in an  effort to  conduct  its
     operations in the most efficient and cost effective manner.  The Trust has
     committed  a  portion  of its  2007  capital  expenditure  budget  towards
     continued research into tertiary recovery methods.

o    Being an industry leader in health, safety and environmental performance -
     The Trust's primary focus continues to be on operating in a safe, reliable
     and responsible  fashion.  The Trust is committed to the platinum level of
     CAPP  Stewardship   reporting  and  continues  to  achieve  reductions  in
     greenhouse gas emissions  under the Canada Climate Change VCR  initiative.
     The Trust's commitment to pursue additional CO2 injection opportunities is
     expected to have the two-fold benefit of enhanced recovery of reserves and
     the  capture  and  containment  of CO2  emissions  which will  benefit the
     environment.  The Trust's  commitment  to safety is evidenced by zero lost
     time incidents reported for employees of the Trust in 2006.

o    Continuing to actively  support local  initiatives  in the  communities in
     which we live and work - The Trust is very actively involved in charitable
     and  philanthropic  causes both in Calgary and in the rural communities in
     which it operates.  ARC  continued to be a strong  supporter of the United
     Way,  Alberta  Cancer  Foundation,  Alberta  Children's  Hospital and many
     community  organizations in rural centres. In addition to the $1.3 million
     of cash donations made to charitable  organizations in 2006 the Trust also
     provided business  expertise,  employee  volunteers and tangible assets as
     needed.

2006 REVIEW AND 2007 GUIDANCE

Following  is a summary  of the  Trust's  2007  Guidance  issued by way of news
release on  November 2, 2006 and a review of 2006  actual  results  compared to
2006 Guidance:

<TABLE>
<CAPTION>
==========================================================================================================================
                                                          2006 Guidance       Actual 2006     % Change     2007 Guidance
==========================================================================================================================
<S>                                                       <C>                 <C>             <C>          <C>
Production (boe/d)                                            63,000             63,056           -            63,000
Expenses ($/boe):
   Operating costs                                              8.40               8.49           1              8.95
   Transportation                                               0.70               0.63         (10)             0.70
   G&A expenses - cash                                          1.65               1.58          (4)             2.25
   G&A expenses - stock compensation plans                      0.60               0.47         (22)             0.20
   Interest                                                     1.35               1.38           2              1.50
   Taxes                                                        0.02               0.01         (50)             0.00
Capital expenditures ($ millions)                                370                365          (1)              360
Weighted average trust units and units issuable (millions)       205                207           1               208
==========================================================================================================================
</TABLE>

<PAGE>

Actual 2006 results were in line with 2006 guidance with only minor  exceptions
as follows:

o    Operating  costs were  slightly  higher  than  guidance  due to  increased
     Alberta electricity rates in the fourth quarter of 2006.

o    Transportation   costs  were  lower  than   guidance  due  to  lower  than
     anticipated transportation costs in the fourth quarter on trucked volumes.

o    Cash G&A  expenses  were  lower  than  guidance  due to  higher  operating
     recoveries  attributed to high levels of capital and operating activity in
     the fourth quarter.

o    Non-cash G&A expenses  were lower than  guidance due to the decline in the
     value of the Trust's whole unit plan  following  the Federal  Government's
     proposed Trust taxation  announcement on October 31, 2006. As the value of
     the whole unit plan is  dependent  upon the trust unit price,  there was a
     considerable  decrease  in the  fourth  quarter  non-cash  whole unit plan
     expense.

o    Interest  expense was slightly  higher than guidance due to increased debt
     levels in the fourth quarter  resulting from high capital and  acquisition
     activity which was partially funded with debt.

o    Weighted average trust units were slightly higher than guidance due to the
     large number of units issued pursuant to the DRIP in the fourth quarter.

There have been no  revisions  to the 2007  Guidance  estimates  as  originally
published on November 2, 2006.


2007 CASH FLOW SENSITIVITY

Below is a table that  illustrates  sensitivities  to pre-hedged cash flow with
operational changes and changes to the business environment:

<TABLE>
<CAPTION>
===================================================================================================
                                                               Impact on Annual Cash Flow
Business Environment                              Assumption             Change            $/Unit
===================================================================================================
<S>                                               <C>              <C>                  <C>
Oil price (US$WTI/bbl) (1)                         $  59.00           $   1.00            $   0.05
Natural gas price (CDN $AECO/mcf) (1)              $  7.25            $   0.10            $   0.03
USD/CAD exchange rate                                 0.88            $   0.01            $   0.06
Interest rate on debt                                 5.2%            %   1.0             $   0.03
OPERATIONAL
Liquids production volume (bbl/d)                     32,200          %   1.0             $   0.02
Gas production volumes (mmcf/d)                       185.0           %   1.0             $   0.02
Operating expenses per boe                         $  8.95            %   1.0             $   0.01
Cash G&A expenses per boe                          $  2.25            %   10.0            $   0.02
===================================================================================================
</TABLE>
(1)  Analysis does not include the effect of hedging contracts.


ASSESSMENT OF BUSINESS RISKS

The ARC  management  team is focused on  long-term  strategic  planning and has
identified the key risks,  uncertainties and opportunities  associated with the
Trust's business that can impact the financial results as follows:

Changes in Tax and  Royalty  Legislation  Income tax laws,  or other  laws,  or
provincial  royalty  programs  relating to the oil and gas  industry may in the
future be changed or interpreted  in a manner that adversely  affects the Trust
or its  Unitholders.  Tax  authorities  having  jurisdiction  over the Trust or
Unitholders  may  disagree  with how the Trust  calculates  its  income for tax
purposes  or how we  calculate  payment  of crown  royalties  or  could  change
administrative practices to the detriment of the Trust and its Unitholders.

On October 31, 2006, the federal government  announced plans to impose a tax of
31.5 per cent on all distributions paid by all income trusts with the exception
of Real Estate Income Trusts.  At the time of writing this MD&A the legislation
has not been passed,  however,  if the legislation is successfully  passed, the
Trust will no longer be able to flow through the Trust's  income to unitholders
on a tax free basis.  The Trust is part of the  Coalition  of  Canadian  Energy
Trusts who are lobbying the  government  to exempt the energy trust sector from
the  proposed  rules.  In the event that the  coalition  is not  successful  in
obtaining  this  exemption the Trust's  distributions  would become  taxable on
January 1, 2011.

In light of the proposed changes, the Trust is actively evaluating  alternative
strategies  that  could be  implemented  to  ensure  that the  Trust's  guiding
principles are still being fulfilled.  The proposed solutions could result in a
change to the Trust's  structure which could impact the amount of distributions
being paid to unitholders.

On February 16,  2007,  the Alberta  government  launched a review of Alberta's
royalty regime for oil sands, conventional oil and gas and coalbed methane. The
review is intended to assess  whether the existing  royalty regime is providing
Albertans  with a  fair  return  on  the  province's  natural  resources  while
maintaining  an  internationally  competitive  system  that  allows the Alberta
economy to continue to prosper. The review,  expected to be completed by August
31,  2007,  may result in  recommendations  which  could  adversely  impact the
current royalty structure in place for the Trust's  conventional  production as
well as the future economics for the Trust's coalbed methane prospects.

<PAGE>

ACCESS TO CAPITAL MARKETS

To the extent that  external  sources of  capital,  including  the  issuance of
additional trust units become limited or unavailable, ARC's ability to make the
necessary  capital  investments  to  maintain or expand its oil and natural gas
reserves could be impaired. To the extent that ARC is required to use cash flow
to  finance  capital  expenditures  or  property  acquisitions,  the  level  of
distributions could be reduced.

Under the proposed  changes in tax  legislation,  the Trust would be subject to
the "undue expansion"  provisions between now and 2011 which would restrict the
amount of equity that ARC can issued for purposes of completing acquisitions.

VOLATILITY OF OIL AND NATURAL GAS PRICES

The Trust's  operational  results and  financial  condition,  and therefore the
amount of distributions paid to the unitholders will be dependent on the prices
received for oil and natural gas production. Oil and gas prices have fluctuated
widely  during  recent years and are  determined by economic and in the case of
oil prices, political factors. Supply and demand factors, including weather and
general economic  conditions as well as conditions in other oil and natural gas
regions impact prices. Any movement in oil and natural gas prices could have an
effect on the Trust's financial condition and therefore on the distributions to
the holders of trust units.  ARC may manage the risk associated with changes in
commodity  prices  by  entering  into  oil  or  natural  gas  price  derivative
contracts. If ARC engages in activities to manage its commodity price exposure,
the Trust may forego the benefits it would  otherwise  experience  if commodity
prices were to increase. In addition, commodity derivative contracts activities
could expose ARC to losses.  To the extent that ARC engages in risk  management
activities  related to  commodity  prices,  it will be subject to credit  risks
associated with counterparties with which it contracts.

VARIATIONS IN INTEREST RATES AND FOREIGN EXCHANGE RATES

Variations  in interest  rates could  result in a  significant  increase in the
amount the Trust pays to service debt, resulting in a decrease in distributions
to  unitholders.  World  oil  prices  are  quoted in US  dollars  and the price
received by Canadian  producers is therefore affected by the Canadian/US dollar
exchange rate that may fluctuate over time. A material increase in the value of
the Canadian dollar may negatively  impact the Trust's net production  revenue.
In addition, the exchange rate for the Canadian dollar versus the US dollar has
increased  significantly  over the last 24 months,  resulting in the receipt by
the Trust of fewer Canadian dollars for its production, which may affect future
distributions.  ARC has initiated  certain  derivative  contracts to attempt to
mitigate  these  risks.  To the  extent  that ARC  engages  in risk  management
activities related to foreign exchange rates, it will be subject to credit risk
associated  with  counterparties  with which it contracts.  The increase in the
exchange rate for the Canadian dollar and future Canadian/US exchange rates may
impact  future  distributions  and the future value of the Trust's  reserves as
determined by independent evaluators.

RESERVES ESTIMATES

The reserves and recovery  information  contained in ARC's independent reserves
evaluation is only an estimate.  The actual  production  and ultimate  reserves
from the properties  may be greater or less than the estimates  prepared by the
independent reserves evaluator.  The reserves report was prepared using certain
commodity  price  assumptions  that are  described in the notes to the reserves
tables.  If lower prices for crude oil, natural gas liquids and natural gas are
realized by the Trust and  substituted  for the price  assumptions  utilized in
those reserves  reports,  the present value of estimated  future net cash flows
for  the  Trust's  reserves  would  be  reduced  and  the  reduction  could  be
significant, particularly based on the constant price case assumptions.

DEPLETION OF RESERVES AND MAINTENANCE OF DISTRIBUTION

ARC's future oil and natural gas reserves and  production,  and  therefore  its
cash  flows,  will be highly  dependent  on ARC's  success  in  exploiting  its
reserves base and acquiring  additional  reserves.  Without reserves  additions
through  acquisition  or  development  activities,  the  Trust's  reserves  and
production  will  decline  over time as the oil and  natural gas  reserves  are
produced out.

There  can  be no  assurance  that  the  Trust  will  make  sufficient  capital
expenditures to maintain  production at current  levels;  nor as a consequence,
that the amount of  distributions by the Trust to unitholders can be maintained
at current levels.

There  can be no  assurance  that  ARC  will be  successful  in  developing  or
acquiring  additional  reserves  on  terms  that  meet the  Trust's  investment
objectives.

ACQUISITIONS

The price paid for reserves  acquisitions  is based on engineering and economic
estimates of the reserves made by independent engineers modified to reflect the
technical views of management.  These assessments  include a number of material
assumptions  regarding such factors as recoverability and marketability of oil,
natural gas,  natural gas liquids and sulphur,  future  prices of oil,  natural
gas,  natural  gas liquids and sulphur  and  operating  costs,  future  capital
expenditures  and  royalties and other  government  levies that will be imposed
over the producing  life of the reserves.  Many of these factors are subject to
change and are beyond the control of the  operators  of the working  interests,
management and the Trust.  In particular,  changes in the prices of and markets
for oil, natural gas, natural gas liquids and sulphur from those anticipated at
the  time  of  making  such  assessments  will  affect  the  amount  of  future
distributions  and as such  the  value  of the  units.  In  addition,  all such
estimates  involve a measure of geological  and  engineering  uncertainty  that
could result in lower  production  and reserves than  attributed to the working
interests.   Actual  reserves  could  vary  materially  from  these  estimates.
Consequently,  the  reserves  acquired may be less than  expected,  which could
adversely impact cash flows and distributions to unitholders.

<PAGE>

ENVIRONMENTAL CONCERNS AND IMPACT ON ENHANCED OIL RECOVERY PROJECTS

The oil and  natural  gas  industry  is  subject  to  environmental  regulation
pursuant  to  local,  provincial  and  federal  legislation.  A breach  of such
legislation  may  result in the  imposition  of fines or  issuance  of clean up
orders in respect of ARC or its  working  interests.  Such  legislation  may be
changed to impose higher standards and potentially  more costly  obligations on
ARC. Furthermore,  management believes the federal political parties, appear to
favor new programs  for  environmental  laws and  regulation,  particularly  in
relation to the reduction of emissions, and there is no assurance that any such
programs,  laws or  regulations,  if  proposed  and  enacted,  will not contain
emission  reduction  targets which ARC cannot meet, and financial  penalties or
charges could be incurred as a result of the failure to meet such  targets.  In
particular there is uncertainty  regarding the Federal  Government's  Clean Air
Act of 2006.  The Clean Air Act proposes to reduce  greenhouse  gas  emissions,
however emission targets and compliance deadlines differ from those outlined in
the Kyoto Protocol which was ratified by Canada.  If passed,  the Clean Air Act
may have adverse operational and financial implications to the Trust.

Additionally,  the potential  impact on the Trust's  operations and business of
the  December  1997 Kyoto  Protocol,  which has been  ratified by Canada,  with
respect to instituting reductions of greenhouse gases, is difficult to quantify
at this time as specific  measures for meeting  Canada's  commitments  have not
been  developed.  Currently,  companies  are  permitted  to emit  CO2  into the
atmosphere with no requirement to capture and re-inject the emissions. In order
for the Trust to carry out its enhanced oil recovery program it is necessary to
obtain CO2 at a cost  effective  rate.  Given that  companies are not forced to
capture  their  emissions,  the  infrastructure  has not  been  put in place to
facilitate this process. Without any additional provisions from the government,
the economic  parameters of the Trust's enhanced oil recovery programs would be
limited.

Although ARC has established a reclamation  fund for the purpose of funding its
currently estimated future  environmental and reclamation  obligations based on
its current knowledge, there can be no assurance that the Trust will be able to
satisfy its actual future environmental and reclamation obligations.

OPERATIONAL MATTERS

The  operation of oil and gas wells  involves a number of operating and natural
hazards that may result in blowouts,  environmental damage and other unexpected
or dangerous  conditions  resulting in damage to operating  subsidiaries of the
Trust and possible  liability to third  parties.  ARC will  maintain  liability
insurance,  where  available,  in amounts  consistent with industry  standards.
Business interruption  insurance may also be purchased for selected facilities,
to the extent  that such  insurance  is  available.  ARC may become  liable for
damages  arising  from such events  against  which it cannot  insure or against
which  it may  elect  not to  insure  because  of high  premium  costs or other
reasons.  Costs  incurred to repair such  damage or pay such  liabilities  will
reduce distributable cash.

Continuing  production  from a property,  and to some extent the  marketing  of
production  there from, are largely  dependent upon the ability of the operator
of the  property.  Approximately  30% of ARC's  production is operated by third
parties.  ARC has  limited  ability  to  influence  costs on  partner  operated
properties.  Operating costs on most  properties  have increased  steadily over
recent  years.  To the extent the  operator  fails to perform  these  functions
properly,  revenue may be reduced.  Payments  from  production  generally  flow
through the  operator  and there is a risk of delay and  additional  expense in
receiving   such  revenues  if  the  operator   becomes   insolvent.   Although
satisfactory title reviews are generally  conducted in accordance with industry
standards,  such reviews do not guarantee or certify that a defect in the chain
of title may not arise to defeat the claim of the Trust to certain  properties.
A reduction of the distributions could result in such circumstances.

DEBT SERVICE AND ADDITIONAL FINANCING

Amounts  paid  in  respect  of  interest  and  principal  on debt  will  reduce
distributions.  Variations in interest rates and scheduled principal repayments
could  result in  significant  changes in the amount  required to be applied to
debt  service  before  payment  of  distributions.  Certain  covenants  of  the
agreements  with ARC's  lenders  may also  limit  distributions.  Although  ARC
believes the credit  facilities  will be sufficient  for the Trust's  immediate
requirements,  there can be no  assurance  that the amount will be adequate for
the future financial  obligations of the Trust or that additional funds will be
able to be obtained.

The lenders will be provided with security over substantially all of the assets
of ARC.  If ARC becomes  unable to pay its debt  service  charges or  otherwise
commits an event of default such as bankruptcy,  the lender may foreclose on or
sell the working interests.

In the normal course of making  capital  investments to maintain and expand the
oil and gas reserves of the Trust,  additional  units are issued from  treasury
that may  result in a decline in  production  per unit and  reserves  per unit.
Additionally,  from time to time the Trust issues units from  treasury in order
to reduce debt and maintain a more optimal capital  structure.  Conversely,  to
the extent  that  external  sources  of  capital,  including  the  issuance  of
additional  units,  become limited or unavailable,  the Trust's ability to make
the  necessary  capital  investments  to  maintain  or  expand  its oil and gas
reserves will be impaired.  To the extent that ARC is required to use cash flow
to finance capital expenditures or property  acquisitions,  to pay debt service
charges or to reduce debt, the level of distributable income will be reduced.

<PAGE>

FORWARD-LOOKING STATEMENT

This  discussion  and analysis  contains  forward-looking  statements as to the
Trusts internal projections,  expectations or beliefs relating to future events
or future  performance  within the meaning of the "safe harbour"  provisions of
the United  States  Private  Securities  Litigation  Reform Act of 1995 and the
Securities  Act  (Ontario).  In some cases,  forward-looking  statements can be
identified  by  terminology  such  as  "may",  "will",   "should",   "expects",
"projects",  "plans",  "anticipates" and similar expressions.  These statements
represent management's expectations or beliefs concerning,  among other things,
future  operating  results  and  various  components  thereof  or the  economic
performance  of ARC  Energy  Trust  ("ARC" or "the  Trust").  The  projections,
estimates and beliefs contained in such forward-looking statements are based on
management's  assumptions  relating to the production  performance of ARC's oil
and gas assets,  the cost and competition  for services  throughout the oil and
gas industry in 2007 and the  continuation  of the current  regulatory  and tax
regime  in  Canada,  and  necessarily  involve  known  and  unknown  risks  and
uncertainties,  including  the  business  risks  discussed  in this  discussion
analysis,  which may cause actual  performance and financial  results in future
periods to differ  materially  from any  projections  of future  performance or
results expressed or implied by such forward-looking  statements.  Accordingly,
readers are  cautioned  that  events or  circumstances  could cause  results to
differ materially from those predicted.  The Trust does not undertake to update
any forward looking information in this document whether as to new information,
future events or otherwise.

ADDITIONAL INFORMATION

Additional information relating to ARC can be found on SEDAR at www.sedar.com.

<PAGE>

<TABLE>
<CAPTION>
ANNUAL HISTORICAL REVIEW
For the year ended December 31
=================================================================================================================================
(CDN $ millions, except per unit amounts)                      2006           2005           2004            2003          2002
=================================================================================================================================
<S>                                                        <C>            <C>             <C>            <C>           <C>
FINANCIAL
Revenue before royalties                                     1,230.5        1,165.2          901.8           743.2         444.8
   Per unit (1)                                                 6.02           6.10           4.85            4.80          3.72
Cash flow                                                      760.6          639.5          448.0           396.2         224.0
   Per unit - basic (1)                                         3.72           3.35           2.41            2.56          1.87
   Per unit - diluted                                           3.71           3.32           2.38            2.48          1.86
Net income                                                     460.1          356.9          241.7           284.6          70.0
   Per unit - basic (2)                                         2.28           1.90           1.32            1.88          0.60
   Per unit - diluted                                           2.27           1.88           1.31            1.82          0.59
Cash distributions                                             484.2          376.6          330.0           279.3         183.6
   Per unit (3)                                                 2.40           1.99           1.80            1.80          1.56
Total assets                                                 3,479.0        3,251.2        2,305.0         2,281.8       1,467.9
Total liabilities                                            1,550.6        1,415.5          755.7           730.0         599.3
Net debt outstanding (4)                                       739.1          578.1          264.8           262.1         347.8
Weighted average units (millions) (5)                          204.4          191.2          186.1           154.7         119.6
Units outstanding and issuable at period end (millions) (5)    207.2          202.0          188.8           182.8         126.4
---------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
---------------------------------------------------------------------------------------------------------------------------------
Geological and geophysical                                      11.4            9.2            5.4             5.7           2.0
Land                                                            32.4            9.1            4.1            4.0              -
Drilling and completions                                       240.5          191.8          140.4           106.2          70.0
Plant and facilities                                            77.6           55.0           41.1            36.5          14.4
Other capital                                                    2.6            3.7            2.8             3.4           1.9
Total capital expenditures                                     364.5          268.8          193.8           155.8          88.3
Property acquisitions (dispositions), net                      115.2           91.3          (58.2)         (161.6)        119.1
Corporate acquisitions (6)                                      16.6          505.0           72.0           721.6            -
Total capital expenditures and net acquisitions                496.3          865.1          207.6           715.8         207.4
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OPERATING
---------------------------------------------------------------------------------------------------------------------------------
Production
   Crude oil (bbl/d)                                          29,042         23,282         22,961          22,886        20,655
   Natural gas (mmcf/d)                                        179.1          173.8          178.3           164.2         109.8
   Natural gas liquids (bbl/d)                                 4,170          4,005          4,191           4,086         3,479
   Total (boe per day 6:1)                                    63,056         56,254         56,870          54,335        42,425
Average prices
   Crude oil ($/bbl)                                           65.26          61.11          47.03           36.90         31.63
   Natural gas ($/mcf)                                          6.97           8.96           6.78            6.40          4.41
   Natural gas liquids ($/bbl)                                 52.63          49.92          39.04           32.19         24.01
   Oil equivalent ($/boe)                                      53.33          56.54          43.13           37.29         28.73
---------------------------------------------------------------------------------------------------------------------------------
RESERVES (7) (company interest)
---------------------------------------------------------------------------------------------------------------------------------
Proved plus probable reserves
   Crude oil and NGL (mbbl)                                  162,193        163,385        123,226         129,663       117,241
   Natural gas (bcf)                                           743.6          741.7          724.5           720.2         408.8
   Total (mboe)                                              286,125        286,997        243,974         249,704       185,371
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TRUST UNIT TRADING (based on intra-day trading)
---------------------------------------------------------------------------------------------------------------------------------
Unit prices
   High                                                        30.74          27.58          17.98           14.87         13.44
   Low                                                         19.20          16.55          13.50           10.89         11.04
   Close                                                       22.30          26.49          17.90           14.74         11.90
Average daily volume (thousands)                                 706            656            420             430           305
=================================================================================================================================
</TABLE>
(1)  Per unit amounts (with the exception of per unit  distributions) are based
     on weighted average units plus units issuable for exchangeable shares.
(2)  Net income in the basic per trust  unit  calculation  has been  reduced by
     interest on the convertible  debentures in 2003 and is based on net income
     after   non-controlling   interest   divided  by  weighted  average  units
     (excluding  units  issuable  for   exchangeable   shares)  for  the  years
     2003-2006.
(3)  Based on number of trust units outstanding at each cash distribution date.
(4)  Net debt  excludes  unrealized  commodity and foreign  exchange  contracts
     asset and liability.
(5)  Includes trust units issuable for outstanding exchangeable shares based on
     the period end exchange ratio
(6)  Represents total  consideration  for the corporate  acquisition  including
     fees but prior to working capital,  asset retirement obligation and future
     income tax liability assumed on acquisition.
(7)  Established reserves for 2002.

<PAGE>

<TABLE>
<CAPTION>
QUARTERLY HISTORICAL REVIEW

=================================================================================================================================
(CDN $ millions, except per unit amounts)                       2006                               2005
=================================================================================================================================
<S>                                             <C>        <C>       <C>        <C>       <C>         <C>       <C>       <C>
FINANCIAL                                           Q4         Q3        Q2         Q1        Q4        Q3        Q2         Q1
Revenue before royalties                           292.5      312.3     306.7      318.9     365.3     310.2     251.6     238.1
   Per unit (1)                                     1.42       1.52      1.51       1.58      1.89      1.62      1.32      1.26
Cash flow                                          174.4      200.3     194.7      191.2     207.6     168.1     121.8     142.0
   Per unit - basic (1)                             0.85       0.98      0.96       0.94      1.07      0.88      0.64      0.75
   Per unit - diluted                               0.84       0.97      0.95       0.94      1.07      0.87      0.63      0.74
Net income                                          56.6      116.9     182.5      104.1     130.5     114.6      73.2      38.6
   Per unit - basic (2)                             0.28       0.58      0.91       0.52      0.68      0.61      0.39      0.21
   Per unit - diluted                               0.28       0.58      0.91       0.52      0.68      0.59      0.39      0.20
Cash distributions                                 122.3      121.4     120.6      119.9     115.7      92.6      84.5      83.9
   Per unit (3)                                     0.60       0.60      0.60       0.60      0.60      0.49      0.45      0.45
Total assets                                     3,479.0    3,335.8   3,277.8    3,279.7   3,251.2   2,483.5   2,427.5   2,303.9
Total liabilities                                1,550.6    1,371.3   1,339.9    1,434.1   1,415.5     912.2     895.2     785.8
Net debt outstanding (4)                           739.1      579.7     567.4      598.9     578.1     357.6     366.2     254.3
Weighted average units (5)                         206.5      205.1     203.7      202.5     193.4     191.7     190.3     189.2
Units outstanding and issuable (5)                 207.2      205.7     204.4      203.1     202.0     192.1     191.3     189.6
---------------------------------------------------------------------------------------------------------------------------------
CAPITAL EXPENDITURES
---------------------------------------------------------------------------------------------------------------------------------
Geological and geophysical                           3.7        2.2       2.8        2.7       3.0       2.3       2.7       1.3
Land                                                11.8        1.4      14.3        4.9       5.5       2.0       0.8       0.8
Drilling and completions                            79.1       76.2      29.8       55.4      60.3      63.6      32.7      35.2
Plant and facilities                                26.5       24.6      10.9       15.6      17.0      14.8       8.7      14.5
Other capital                                        0.8        0.5       0.8        0.5       2.0       0.3       0.6       0.7
Total capital expenditures                         121.9      104.9      58.6       79.1      87.8      83.0      45.5      52.5
Property acquisitions (dispositions) net            76.4        8.4       2.8       27.6       3.0       5.9      78.7       3.7
Corporate acquisitions (6)                          16.6          -         -          -     462.8         -      42.2         -
Total capital expenditures and net acquisitions    214.9      113.3      61.4      106.7     553.6      88.9     166.4      56.2
---------------------------------------------------------------------------------------------------------------------------------
OPERATING
---------------------------------------------------------------------------------------------------------------------------------
Production
   Crude oil (bbl/d)                              29,605     29,108    27,805     29,651    25,534    23,513    22,046    21,993
   Natural gas (mmcf/d)                            179.5      173.4     178.5      185.0     177.9     168.2     173.1     176.1
   Natural gas liquids (bbl/d)                     4,144      4,166     4,247      4,120     3,943     4,047     3,962     4,072
   Total (boe per day 6:1)                        63,663     62,178    61,803     64,600    59,120    55,592    54,860    55,410
Average prices
   Crude oil ($/bbl)                               58.26      71.84     71.86      59.53     62.12     69.37     58.37     53.63
   Natural gas ($/mcf)                              6.99       6.10      6.35       8.40     12.05      9.08      7.42      7.20
   Natural gas liquids ($/bbl)                     46.51      56.60     54.44      52.91     57.14     50.43     46.13     46.57
   Oil equivalent ($/boe)                          49.94      54.59     54.54      54.86     67.16     60.66     50.40     47.74
---------------------------------------------------------------------------------------------------------------------------------
TRUST UNIT TRADING (based on intra-day trading)
---------------------------------------------------------------------------------------------------------------------------------
Unit prices
High                                               29.22      30.74     28.61      27.51     27.58     24.20     20.30     20.40
Low                                                19.20      25.25     24.35      25.09     20.45     19.94     16.88     16.55
Close                                              22.30      27.21     28.00      27.36     26.49     24.10     19.94     18.15
Average daily volume (thousands)                   1,125        614       548        546       653       599       605       895
=================================================================================================================================
</TABLE>
(1)  Per unit amounts (with the exception of per unit  distributions) are based
     on weighted average units plus units issuable for exchangeable shares.
(2)  Net income per unit is based on net income after non-controlling  interest
     divided  by  weighted   average  units   (excluding   units  issuable  for
     exchangeable shares).
(3)  Based on number of trust units outstanding at each cash distribution date.
(4)  Net debt  excludes  unrealized  commodity and foreign  exchange  contracts
     asset and liability.
(5)  Includes trust units issuable for outstanding exchangeable shares based on
     the period end exchange ratio.
(6)  Represents total  consideration  for the corporate  acquisition  including
     fees but prior to working capital,  asset retirement obligation and future
     income tax liability assumed on acquisitio